IDACORP INC (Form: 10-K, Received: 02/23/2017 08:12:38)

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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, 2016



	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, 2016 ):



IDACORP, Inc.:	$	4,052,238,968	Idaho Power Company:	None



Number of shares of common stock outstanding as of February 17, 2017:
IDACORP, Inc.:	50,396,773
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 2017 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	71
Item 8	Financial Statements and Supplementary Data	73
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	128
Item 9A	Controls and Procedures	128
Item 9B	Other Information	132

Part III

Item 10	Directors, Executive Officers and Corporate Governance*	132
Item 11	Executive Compensation*	132
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*	132
Item 13	Certain Relationships and Related Transactions, and Director Independence*	133
Item 14	Principal Accountant Fees and Services*	133

Part IV

Item 15	Exhibits and Financial Statement Schedules	134

Signatures		145

* 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 2017 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	IPUC	-	Idaho Public Utilities Commission
AFUDC	-	Allowance for Funds Used During Construction	IRP	-	Integrated Resource Plan
APCU	-	Annual Power Cost Update	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
CAA	-	Clean Air Act	MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
CO ₂	-	Carbon Dioxide	MW	-	Megawatt
CSPP		Cogeneration and Small Power Production	MWh	-	Megawatt-hour
CWA	-	Clean Water Act	NAAQS	-	National Ambient Air Quality Standards
EIS	-	Environmental Impact Statement	NMFS	-	National Marine Fisheries Service
EPA	-	U.S. Environmental Protection Agency	NOx	-	Nitrogen Oxide
EPS	-	Earnings Per Share	O&M	-	Operations and Maintenance
ESA	-	Endangered Species Act	OATT	-	Open Access Transmission Tariff
FCA	-	Idaho Fixed Cost Adjustment	OPUC	-	Public Utility Commission of Oregon
FERC	-	Federal Energy Regulatory Commission	PCA	-	Idaho 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
HCC	-	Hells Canyon Complex	RPS	-	Renewable Portfolio Standard
Ida-West	-	Ida-West Energy Company, a subsidiary of IDACORP, Inc.	SEC	-	U.S. Securities and Exchange Commission
Idaho ROE	-	Idaho-jurisdiction return on year-end equity	SMSP	-	Security Plan for Senior Management Employees
IERCo	-	Idaho Energy Resources Co., a subsidiary of Idaho Power Company	SO2	-	Sulfur Dioxide
IESCo	-	IDACORP Energy Services Co., a subsidiary of IDACORP, Inc.	USFWS	-	U.S. Fish and Wildlife Service
IFS	-	IDACORP Financial Services, Inc., a subsidiary of IDACORP, Inc.

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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, future events, or performance, often, but not always, through the use of words or phrases such as "anticipates," "believes," "estimates," "expects," "guidance," "intends," "potential," "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 U.S. 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;


•	the expense and risks associated with capital expenditures for infrastructure, and the timing and availability of cost recovery for such expenditures;


•	changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power's service area and the loss or change in the business of significant customers, and their associated impacts on loads and load growth, and the availability of regulatory mechanisms that allow for timely cost recovery in the event of those changes;


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


•	administration of reliability, security, and other requirements for system infrastructure required by the Federal Energy Regulatory Commission and other regulatory authorities, which could result in penalties and increase costs;


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


•	variable hydrological conditions and over-appropriation of surface and groundwater in the Snake River Basin, which may impact the amount of power generated by Idaho Power's hydroelectric facilities;


•	the ability to acquire fuel, power, and transmission capacity under reasonable terms, particularly in the event of unanticipated power demands, lack of physical availability, transportation constraints, or a credit downgrade;

•

accidents, fires (either at or caused by Idaho Power facilities), explosions, and mechanical breakdowns that may occur while operating and maintaining Idaho Power assets, 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, and regulatory fines and penalties;


•	the increased costs and operational challenges associated with purchasing and integrating intermittent renewable energy sources into Idaho Power's resource portfolio;


•	disruptions or outages of Idaho Power's generation or transmission systems or of any interconnected transmission system may cause Idaho Power to incur repair costs and purchase replacement power at increased costs;


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

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•	reductions in credit ratings, which could adversely impact access to capital markets, increase costs of borrowing, and would require the posting of additional collateral to counterparties pursuant to credit and contractual arrangements;


•	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;


•	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, regulations and orders, 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;


•	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 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;


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


•	adoption of or changes in accounting policies and principles, changes in accounting estimates, and new U.S. 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, 2016, IDACORP had 2,008 full-time employees, 1,999 of whom were employed by Idaho Power, and 12 part-time employees, 10 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 Reports 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 535,000 general business customers in southern Idaho and eastern Oregon as of December 31, 2016 . Over 444,000 of these customers are residential. Idaho Power’s principal commercial and industrial customers are involved in food processing, 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 9 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 3 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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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 (FPA), Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its open access transmission tariff (OATT). 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 sometimes result in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. In these instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet and recorded on the income statement when recovered or returned in rates or when otherwise directed to begin amortization by a regulator. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers that are expected to be refunded. 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’s business strategy seeks to balance the interests of owners, customers, employees, and other stakeholders while maintaining the company’s financial stability and flexibility. Idaho Power's three-part business strategy includes three core focuses—improving its core business, growing revenues, and enhancing the brand and positioning the company for the future. IDACORP continues to focus on its core business and its goal of generating returns for its shareholders and long-term shareholder value.

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 critical factors 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 continually evaluates the need to request changes to its retail electricity price structure to cover its operating costs and to earn a fair return on its investments. Idaho Power uses general rate cases, power cost adjustment mechanisms in Idaho and Oregon, a fixed cost adjustment (FCA) mechanism in Idaho, 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, or that its costs will be recovered in advance of or at the same time as the costs are incurred.

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 amounts recorded under specific authorization from the IPUC or OPUC but deferred for recovery or refund. 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 power cost adjustment mechanisms, FCA mechanism, and energy efficiency rider. The Idaho and Oregon power cost adjustment 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 most of its energy efficiency program costs through an energy efficiency rider on customer bills.

Wholesale Markets : 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 market power prices at the time when those resources are available. A reduction in either factor leads to lower off-system sales revenue.

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,
	2016			2015			2014
General business revenues (thousands of dollars)
Residential	$	514,954		$	512,068		$	500,195
Commercial	302,650			306,178			299,462
Industrial	182,590			182,254			182,675
Irrigation	156,505			164,403			158,654
Provision for rate refund for sharing mechanism	—			(3,159		)	(7,999		)
Deferred revenue related to Hells Canyon Complex relicensing AFUDC	(10,706		)	(10,706		)	(10,706		)
Total general business revenues	1,145,993			1,151,038			1,122,281
Off-system sales	25,205			30,887			77,165
Other	88,155			85,580			79,205
Total revenues	$	1,259,353		$	1,267,505		$	1,278,651
Energy sales (thousands of MWh)
Residential	5,004			4,977			4,965
Commercial	3,999			4,045			3,944
Industrial	3,243			3,196			3,217
Irrigation	1,950			2,047			1,966
Total general business	14,196			14,265			14,092
Off-system sales	1,186			1,254			2,220
Total	15,382			15,519			16,312

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. However, alternative methods of generation, including customer-owned solar and other forms of distributed generation, compete with Idaho Power for sales to existing customers. Also, development of new technologies and services to help energy consumers manage energy in new ways could alter demand for Idaho Power's electric energy. Idaho Power also competes with fuel distribution companies in serving the energy needs of customers for space heating, water heating, and appliances.

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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.

In return for agreeing to provide service to all customers within a defined service area, electric utilities are typically provided with an exclusive right to provide service in that service area. However, certain prescribed areas within Idaho Power's service area, such as municipalities or Native American Tribal reservations, may elect not to take service from Idaho Power and instead operate as a municipal electric utility or otherwise as a separate entity. In such cases, the entity would be required to purchase or otherwise obtain rights (such as by contract) to Idaho Power's distribution infrastructure within the municipal or other designated area. Idaho Power would have no responsibility for providing electric service to the municipal or separate entity, absent Idaho Power's voluntary execution of an agreement to provide that service. Separately, the Shoshone-Bannock Tribes, located in southeastern Idaho, has considered the adoption of a utility code applicable to electric utilities operating within the Shoshone-Bannock Tribal Reservation (Reservation). The tribal utility code, if adopted, could ultimately lead to Idaho Power's cessation of its historical provision of service to the Reservation and could result in either no or a limited electric service relationship with the Reservation, or could result solely in Idaho Power's sale of power to the Reservation pursuant to a power purchase agreement. Idaho Power estimates that the average load for the Reservation over the prior five years is approximately 14 Megawatts (MW).

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, supply constraints, 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's power cost adjustment mechanisms 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 MW, set on July 2, 2013, at which time Idaho Power had deployed 30 MW of demand response programs to mitigate the load demand. On January 6, 2017, Idaho Power tied its highest all-time winter peak demand of 2,527 MW, which was originally set on December 10, 2009. Idaho Power's peak demand during 2016 was 3,299 MW. 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 that follows shows Idaho Power’s total power supply for the last three years.



	MWh			Percent of Total Generation
	2016	2015	2014	2016		2015		2014
	(thousands of MWh)
Hydroelectric plants	6,408	5,910	6,170	53	%	47	%	47	%
Coal-fired plants	4,045	4,676	5,851	33	%	37	%	44	%
Natural gas-fired plants	1,722	2,076	1,175	14	%	16	%	9	%
Total system generation	12,175	12,662	13,196	100	%	100	%	100	%

Purchased power - cogeneration and small power production	2,314	2,008	2,286
Purchased power - other	2,023	1,784	1,867
Total purchased power	4,337	3,792	4,153
Total power supply	16,512	16,454	17,349

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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 water available for hydroelectric power generation depends on several factors—the amount of snowpack in the mountains upstream of Idaho Power’s hydroelectric facilities, upstream reservoir storage, springtime precipitation and temperatures, main river and tributary base flows, the condition of the Eastern Snake Plain Aquifer and its spring flow impact, summer time irrigation withdrawals and returns, and upstream reservoir regulation. Idaho Power actively participates in collaborative work groups focused on water management issues in the Snake River Basin, with the goal of preserving 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. The result is a greater reliance on other generation resources and power purchases. In 2016, low upstream reservoir carryover (primarily in the upper Snake River basin) resulted in reduced downstream flow releases. Additionally, although snowpack accumulation was near-normal on April 1, 2016, the snowpack melted earlier than usual. The combined effect was lower than median hydro production of 6.4 million MWh in 2016. In 2015, below-normal snow accumulation resulted in a lower than median hydro production of 5.9 million MWh. The Northwest River Forecast Center of the National Oceanic Atmospheric Administration reported that the 2016 April through July inflow volume into Brownlee Reservoir (the uppermost reservoir of Idaho Power's Hells Canyon Complex) was only 73 percent of normal. By comparison, the 2015 April through July Brownlee Reservoir inflow was 46 percent of normal. For 2017, Idaho Power estimates annual generation from its hydroelectric facilities to be 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 agencies. 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, 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.

BCC supplies coal to the Jim Bridger power plant. IERCo, a wholly-owned subsidiary of Idaho Power, owns a one-third interest in BCC and PacifiCorp owns a two-third interest in BCC and is the operator of the Bridger Coal Mine. The mine operates under a long-term sales agreement that provides for delivery of coal through 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. Idaho Power's existing coal inventory at the North Valmy plant is expected to meet Idaho Power's projected coal requirements at the plant through at least 2017. Idaho Power expects to be able to obtain future coal requirements through coal supply contracts. In October and November 2016, Idaho Power filed applications with the IPUC and OPUC, respectively, requesting authorization to accelerate depreciation for the North Valmy power plant, to allow the plant to be fully depreciated by December 31, 2025. For additional information on the filings, see the “Regulatory Ma

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tters” section of Part II, Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A).

Portland General Electric Company is the operator of the Boardman power plant. Idaho Power believes that it has sufficient inventory and coal contracts to supply the Boardman plant with fuel through 2017. The Boardman plant receives coal through annual contracts with suppliers from the Powder River Basin in northeast Wyoming. Idaho Power expects to meet future coal needs through similar contracts. 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.

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 but generally contain the right for Idaho Power to extend the term. In addition to the long-term gas transportation service agreements, Idaho Power has entered into a long-term storage service agreement with Northwest Pipeline for 131,453 MMBtu of total storage capacity at the Jackson Prairie Storage Project. This firm storage contract expires in 2043. Idaho Power purchases and stores natural gas with the intent of fulfilling needs as identified for seasonal peaks or to meet system requirements.

As of December 31, 2016, approximately 6.5 million MMBtu of natural gas was financially hedged for physical delivery for the operational dispatch of the Langley Gulch plant through June 2018. 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 requirements, 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 2016 and 2015 , Idaho Power purchased 2.0 million MWh and 1.8 million MWh of power through wholesale market purchases at an average cost of $42.04 per MWh and $49.57 per MWh, respectively. During 2016 and 2015 , Idaho Power sold 1.2 million MWh and 1.3 million MWh of power in wholesale market sales, with an average price of $21.25 per MWh and $24.63 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:


•	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 contract term continues through 2020. Idaho Power has the right to renew the agreement for an additional five-year term.


•	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.

PURPA Power Purchase Contracts : Idaho Power purchases power from PURPA projects as mandated by federal law. As of December 31, 2016, Idaho Power had contracts with on-line PURPA-related projects with a total of 945 MW of nameplate generation capacity, with an additional 178 MW nameplate capacity of projects projected to be on-line in 2017 and an additional 9 MW expected to be added in 2019. The power purchase contracts for these projects have original contract terms

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ranging from one to 35 years. The expense and volume of PURPA project power purchases during the last three years is included in the following table:



	Year Ended December 31,
	2016		2015		2014
PURPA contract expense (in thousands)	$	153,665	$	131,340	$	144,617
MWh purchased under PURPA contracts (in thousands)	2,314		2,008		2,286
Average cost per MWh from PURPA contracts	$	66.41	$	65.41	$	63.26

Pursuant to the requirements of PURPA, the IPUC and OPUC 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 area, 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 area if it has the ability to receive power at the facility’s requested point of delivery on Idaho Power's system.


•	The IPUC jurisdictional portion of the costs associated with PURPA contracts is fully recovered through base rates and the Idaho PCA mechanism, and the OPUC jurisdictional portion is recovered through base rates and an Oregon power cost recovery mechanism. Thus, the primary impact of high power purchase costs under PURPA contracts is on customer rates.


•	The IPUC issued an order in August 2015 that revised the standard PURPA power purchase contract term for new contracts to 2 years from the previously required 20-year term.


•	OPUC jurisdictional regulations have generally provided for PURPA standard contract terms of up to 20 years.


•	The IPUC requires Idaho Power to pay "published avoided cost" rates for all wind and solar projects that are smaller than 100 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 solar PURPA qualifying facilities with a nameplate rating of 3 MW or less and all other types of projects with a nameplate rating of 10 MW or less. Idaho Power is required to 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, are engaged in proceedings at the OPUC relating to PURPA contracts. The OPUC issued orders in 2016 pertaining to contract term, project eligibility for standard rates, and standard avoided cost calculations. Other ongoing OPUC proceedings relate to, among other issues, the prices paid for energy purchased from PURPA projects and solar integration charges. Refer to Part II - Item 7 - MD&A - "Regulatory Matters - Renewable and Other Energy Contracts " for a summary of those proceedings.

Anticipated Participation in Western Energy Imbalance Market : 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 balancing area. In contrast, energy imbalance markets use automated intra-hour economic dispatch of generation from committed resources to serve loads. The California ISO and PacifiCorp implemented a new energy imbalance market in 2014 (Western EIM) under which the parties enabled their systems to interact for dispatch purposes. The Western EIM is intended to reduce the power supply 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 the Western EIM is voluntary and available to all balancing authorities in the western United States. Following an evaluation of the potential power supply cost savings and other advantages, system upgrade requirements, and estimated capital and ongoing operating costs, in April 2016, Idaho Power executed an agreement under which it intends to, subject to regulatory approval and other conditions, participate in the Western EIM. Idaho Power anticipates that it will commence participation in the Western EIM in the spring of 2018. In August 2016, Idaho Power filed an application with the IPUC requesting specified regulatory accounting treatment associated with its participation in the Western EIM. In January 2017, the IPUC issued an order authorizing Idaho Power’s requested deferral accounting treatment for costs associated with joining the Western EIM. Idaho Power can defer costs incurred until the earlier of when Idaho Power requests recovery of t

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he costs and the deferral balance or the end of 2018. Recovery of deferred costs will be addressed in a future IPUC proceeding.

Transmission Services

Electric transmission systems deliver energy from electric generation facilities to distribution systems for final delivery to customers. Transmission systems are designed to move electricity over long distances because generation facilities can be located hundreds of miles away 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, the transmission grid covering much of western North America. Idaho Power provides wholesale transmission service for eligible transmission customers on a non-discriminatory basis. Idaho Power is a member of the WECC, the Northwest PowerPool, 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 1,000-mile, 500-kV transmission project between a station located near Douglas, 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 2015. Idaho Power is presently preparing the 2017 IRP, which Idaho Power anticipates filing in June 2017. 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.

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.

The load forecast assumptions Idaho Power expects to use in the 2017 IRP are included in the table below, together with the average annual growth rate assumptions used in the prior two IRPs. The rate of load growth can impact the timing and extent of

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development of resources, such as new generation plants or transmission infrastructure, to serve those loads.



	Forecast for 2016-2021 Period		20-Year Forecast
	Annual Growth Rate: Retail Sales (Billed MWh)	Annual Growth Rate: Annual Peak (Peak Demand)	Annual Growth Rate: Retail Sales (Billed MWh)	Annual Growth Rate: Annual Peak (Peak Demand)
2017 IRP	1.3%	1.4%	1.0%	1.4%
2015 IRP	1.1%	1.6%	1.2%	1.5%
2013 IRP	1.2%	1.6%	1.1%	1.4%

The 2015 IRP identified a preferred resource portfolio, which included the completion of the Boardman-to-Hemingway 500-kV transmission line and the potential early retirement of the North Valmy power plant, both in 2025, with no other new resource needs prior to 2025. The near-term action plan also included commencement of an economic evaluation of environmental control retrofits for units 1 and 2 at the Jim Bridger power plant. However, as noted in the 2015 IRP, there is considerable uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of third party development of renewable resources, implementation of the U.S. Environmental Protection Agency's (EPA) rules under Section 111(d) of the Clean Air Act (CAA), the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of plant retirements. These and other uncertainties could result in changes to the desirability of the preferred portfolio and adjustments to the timing and nature of anticipated and actual actions.

Energy Efficiency and Demand Response Programs: Idaho Power’s energy efficiency and demand response portfolio is comprised of 22 programs. These energy efficiency programs target energy savings across the entire year, while the demand response programs target system demand reduction in the summer. The 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 generation or transmission 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 heating, ventilation and cooling equipment, energy efficient building techniques, 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 cycling of central air conditioners for residential customers, interruption of irrigation pumps, and reduction of commercial and industrial demand through actions taken by business owners and operators; and


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

In 2016, Idaho Power’s energy efficiency programs reduced energy usage by approximately 142,000 MWh. For 2016, Idaho Power had a demand response available capacity of approximately 392 MW. In 2016 and 2015, Idaho Power expended approximately $43 million and $39 million, respectively, on both 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 power cost adjustment mechanisms.

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 impacts Idaho Power’s operations due to the cost of installation and operation of equipment and facilities required for compliance with environmental regulations, the modification of system operations to accommodate environmental regulations, and the cost of acquiring and complying with permits and licenses. In addition to generally applicable regulations, Idaho Power's three coal-fired power plants, three natural gas combustion turbine power plants, and 17 hydroelectric generating plants are subject to a broad range of environmental requirements, including those related to air and water quality, waste materials, and endangered species. For a more detailed discussion of these and other environmental issues, refer to Item 7 - MD&A - "Environmental Matters" in this report.

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



	2017		2018 - 2019
Capital expenditures:
License compliance and relicensing efforts at hydroelectric facilities	$	21	$	27
Investments in equipment and facilities at thermal plants	5		15
Total capital expenditures	$	26	$	42
Operating expenses:
Operating costs for environmental facilities - hydroelectric	$	20	$	41
Operating costs for environmental facilities - thermal	12		32
Total operations and maintenance	$	32	$	73

Idaho Power anticipates that finalization and implementation of a number of federal and state rulemakings and other proceedings addressing, among other things, greenhouse gases 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. Idaho Power would seek to recover those increased costs through the ratemaking process.

Idaho Power monitors environmental requirements and assesses whether environmental control measures are or remain economically appropriate. Continued review of the economic appropriateness of further investments in coal-fired plants 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 filed an application with the IPUC and OPUC in October and November 2016, respectively, requesting accelerated depreciation of the North Valmy plant in connection with the potential early closure of the plant. Idaho Power is also assessing the economic desirability of potential future investments in additional selective catalytic reduction technology at the Jim Bridger coal-fired plant.

Voluntary CO ₂ Intensity Reduction Goal: Idaho Power is engaged in voluntary greenhouse gas emissions (GHG) 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 (CO ₂ ) emissions intensity for the 2010 through 2013 time period to a level of 10 to 15 percent below Idaho Power's 2005 CO ₂ emissions intensity of 1,194 lbs CO ₂ /MWh. The combination of effective utilization of hydroelectric projects, above average stream flows in some years, reduced usage of coal-fired facilities, the purchase of renewable energy, and the addition of the Langley Gulch natural gas-fired power plant positioned Idaho Power to extend its CO ₂ 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. Idaho Power achieved its initial reduction goal, as well as its extended goal, through 2015. Idaho Power's average CO ₂ emissions intensity from company-owned resources for the 2010 through 2015 period was 21 percent below the 2005 CO ₂ emissions intensity level.

In 2015, Idaho Power further extended and expanded the goal, seeking to reduce the company-owned resource portfolio average CO ₂ emissions intensity to 15-20 percent below 2005 levels for the 2010-2017 period.

Idaho Power's estimated historic CO ₂ emissions intensity from its generation facilities, as submitted to the Carbon Disclosure Project, was as follows:



	2011	2012	2013	2014	2015
Emissions Intensity (lbs CO ₂ /MWh)	677	871	1,135	1,019	952

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IDACORP FINANCIAL SERVICES, INC.

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, 2016 , the unamortized amount of IFS’s portfolio was approximately $8 million ($175 million in gross tax credit investments, net of $167 million of accumulated amortization). IFS generated tax credits of $2.6 million , $3.3 million , and $5.2 million in 2016 , 2015 , and 2014 , respectively. In 2016, IFS received distributions related to fully-amortized affordable housing investments that reduced IDACORP's income tax expense by $1.7 million .

IDA-WEST ENERGY COMPANY

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 approximately $8 million in both 2016 and 2015 and $9 million in 2014 .

EXECUTIVE OFFICERS OF THE REGISTRANTS

The names, ages, and positions of the executive officers of IDACORP and Idaho Power are listed below (in alphabetical order), 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.

DARREL T. ANDERSON, 58


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


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


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


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


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


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

BRIAN R. BUCKHAM, 38


•	Vice President and General Counsel of IDACORP, Inc. and Idaho Power Company, April 2016 - present


•	In-house legal counsel of IDACORP, Inc. and Idaho Power Company, April 2010 - March 2016

LISA A. GROW, 51


•	Senior Vice President of Operations of Idaho Power Company, January 2016 - present


•	Senior Vice President - Power Supply of Idaho Power Company, October 2009 - December 2015

STEVEN R. KEEN, 56


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


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


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


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

LONNIE KRAWL, 53


•	Senior Vice President of Administrative Services and Chief Human Resources Officer of Idaho Power Company, April 2016 - present


•	Senior Vice President of Administrative Services and Chief Information Officer of Idaho Power Company, January 2016 - March 2016


•	Vice President and Chief Information Officer of Idaho Power Company, October 2013 - December 2015


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

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JEFFREY L. MALMEN, 49


•	Senior Vice President of Public Affairs of IDACORP, Inc. and Idaho Power Company, April 2016 - present


•	Vice President of Public Affairs of IDACORP, Inc. and Idaho Power Company, October 2008 - March 2016

TESSIA PARK, 55


•	Vice President of Power Supply of Idaho Power Company, January 2016 - present


•	Director of Load Serving Operations of Idaho Power Company, September 2012 - December 2015


•	Operating Projects Manager of Idaho Power Company, January 2011 - September 2012

KEN W. PETERSEN, 53


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


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

N. VERN PORTER, 57


•	Vice President of Customer Operations of Idaho Power Company, January 2016 - present


•	Senior Vice President of Customer Operations of Idaho Power Company, April 2015 - December 2015


•	Vice President of Idaho Power Company, January 2014 - April 2015


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


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

ITEM 1A. RISK FACTORS

IDACORP and Idaho Power operate in a highly regulated 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 making any investment decisions relating to IDACORP or Idaho Power.

If state public utility commissions or the Federal Energy Regulatory Commission authorize retail or transmission customer rates that under-collect or delay the collection through customer rates of the amount 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 IPUC and OPUC authorize Idaho Power to charge customers for its retail services, and the tariff rate that the FERC 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. Idaho Power's ability to recover its costs and earn a reasonable rate of return can be affected by many regulatory factors, including the timing difference between when costs are incurred and when those costs are recovered in customers’ rates (often called "regulatory lag" in the utility industry), and differences between the costs embedded in rates and the amount of actual costs incurred. Idaho Power is often required to incur costs before the IPUC, OPUC, or FERC approves the recovery of those costs, and the IPUC, OPUC, and FERC may not allow Idaho Power to recover some or all of those costs on the basis that Idaho Power did not reasonably or prudently incur those costs or for other reasons. While rate regulation is premised on the assumption that rates established are fair, just, and reasonable, regulators have considerable discretion in applying this standard. In response to economic, political, legislative, public policy, and regulatory pressures, Idaho Power may be subject to rate increase moratoriums, rate reductions or refunds, limits on rate increases, and lower allowed rates of return on investments. 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. Denial or probable denial of recovery by regulators may cause Idaho Power to record an impairment of its assets. 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. Adverse outcomes in regulatory proceedings or significant regulatory lag may adversely affect cash flows and earnings and result in lower credit ratings, reduced access to capital and higher financing costs, and reductions or delays in planned capital expenditures.

For additional information relating to Idaho Power's regulatory framework and regulatory matters, see Part I - Item 1 - "Business - Utility Operations," Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report,

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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 mechanisms may not function as intended and are subject to change, 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. 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 of the difference between these two amounts is deferred for future recovery from, or refund to, customers through rates. In recent years, the volatility in power supply costs has been significant, in large part due to fluctuations in hydroelectric generation conditions and high costs for the purchase of renewable energy under mandatory long-term contracts. While the power cost adjustment mechanisms function to mitigate the potentially adverse impact on net income of power supply cost volatility, the mechanisms do not eliminate the cash flow impact of that volatility. When power costs rise above the level recovered in current retail rates, Idaho Power incurs the costs but recovery of those costs is deferred to a subsequent collection period, which can adversely affect Idaho Power’s operating cash flow and liquidity until those costs are recovered from customers. The fixed cost adjustment mechanism is a decoupling mechanism designed to remove Idaho Power's disincentive to invest in energy efficiency activities by allowing Idaho Power to charge residential and small commercial customers when it recovers less than the base level of fixed costs per customer that the IPUC authorized for recovery in the most recent general rate case. The power cost and fixed cost adjustment mechanisms are generally subject to change at the discretion of applicable state regulators, who could decide to modify or eliminate either mechanism in a manner that adversely impacts IDACORP's and Idaho Power's financial condition, cash flows, and results of operations.

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 . Growth in the number of customers and customers' use of electricity are affected by a number of factors, such as population growth or decline in Idaho Power's service area, weak economic conditions, expansion or loss of service area, changes in customer needs and expectations, adoption rates of energy efficiency measures, customer-generated power such as from rooftop solar panels, demand-side management requirements, and economic conditions. Many electric utilities, including Idaho Power, have experienced a decline in usage per customer, in part attributable to energy efficiency activities. State or federal regulations may be enacted to require mandatory energy conservation or technological advances that increase energy efficiency, which could further reduce usage per customer. Also, changing customer needs and expectations could lead to lower customer satisfaction, reduced loyalty, difficulty in obtaining rate increases, and customers seeking alternative sources of energy. If customers choose to generate their own energy or replace electric power for heating with natural gas, demand for Idaho Power's energy may decline and adversely impact the affordability of our services for remaining customers. While Idaho Power has recently experienced a net growth in usage due to an increase in the number of customers, when adjusted for the impacts of weather, the average monthly usage on a per customer basis for Idaho residential customers has declined from 1,051 kWh in 2009 to 954 kWh in 2016. Rate mechanisms, such as the Idaho fixed cost adjustment, are designed to address the financial disincentive associated with promoting energy efficiency activities, but there is no assurance that the mechanism will result in full or timely collection of Idaho Power's fixed costs, which are currently collected in large part through the company's kWh energy rates that are based on historical sales volume. Any undercollection of fixed costs would adversely impact revenues, earnings, and cash flows. The formation of municipal utilities or similar entities for distribution systems within Idaho Power's service area could also result in a load decrease. The loss of loads resulting from some of these events may result in IDACORP and Idaho Power modifying or eliminating large generation or transmission projects. This could in turn result in reduced revenues as well as write-downs or write-offs if regulators determine that the costs of the projects were incurred imprudently, which could have a material adverse impact on IDACORP's and Idaho Power's financial condition, results of operations, and cash flows.

Conversely, if Idaho Power were to experience an unanticipated increase in the demand for energy through, for example, the rapid addition of new industrial and commercial customers, Idaho Power may be required to rely on higher-cost purchased power to meet peak system demand and may 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 the sales to the new customers, and Idaho Power is unable to secure timely and full rate relief to recover those increased costs, the resulting imbalance could have an adverse effect on IDACORP's and Idaho Power's financial condition, results of operations, and cash flows.

IDACORP's and Idaho Power's operating results fluctuate seasonally and can be adversely affected by changes in weather conditions and severe weather, including as a result of climate change. 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

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and the timing and amount of precipitation, among other factors, can also create significant seasonal changes in usage. Seasonality of revenues may be further impacted 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, weather conditions and the timing and extent of precipitation can cause IDACORP's and Idaho Power's results of operations and financial condition to fluctuate seasonally, quarterly, and from year to year.

Some scientists have predicted that increasing concentrations of GHG in the earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other extreme weather events. If such effects were to occur, Idaho Power's operations could be adversely affected and its cost of providing service could increase. Extreme weather events and their associated impacts (such as fires, high winds, and snow loading) can damage generation facilities and disrupt transmission and distribution systems, causing service interruptions and extended outages through downed transmission and distribution lines, increasing supply chain costs and limiting Idaho Power's ability to meet customer energy demand. Sustained drought conditions are likely to decrease power generation from hydroelectric plants. 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. Damage and disruption in generation, transmission, and distribution systems due to weather-related factors also often increases O&M expenses. Costs incurred as a result of such events might not be recovered through customer rates if the costs incurred are greater than those allowed for recovery by regulators, and the costs of repair and replacing infrastructure or liability for personal injury or property damage may not be covered in full by insurance.

New advances in power generation, energy efficiency, or other technologies that impact the power utility industry could decrease revenues . The increasing cost of energy in the electric utility industry has encouraged the development of new technologies for power generation, power storage, and energy efficiency. In particular, in recent years the cost of solar generation has decreased significantly, and there are federal tax incentives in place to help further reduce the cost of solar generation. There is potential that customer-owned 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 and high-efficiency appliances. 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 adjust its rate design or maintain adequate regulatory mechanisms allowing for timely cost recovery, declining usage from customer-owned generation sources and energy efficiency would result in under-recovery of Idaho Power's costs and reduce revenues, which would impact IDACORP's and Idaho Power's financial condition and results of operations.

Capital expenditures for infrastructure, risks associated with permitting and 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;


•	defaults by contractors;


•	equipment, engineering, and design failures;


•	unexpected environmental and geological problems;


•	the effects of adverse weather conditions;


•	availability of financing;


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


•	delays and costs associated with disputes and litigation with third parties.

The occurrence of any of these risks could cause Idaho Power to operate at reduced capacity levels, which in turn could reduce revenues, increase expenses, or cause Idaho Power to incur penalties. If Idaho Power is unable or unwilling to complete the permitting or construction of a project, or incurs costs that regulators do not deem prudent, it may be unable to recover its costs

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in full through rates or on a timely basis. Further, if Idaho Power is unable to secure permits or joint funding commitments to develop transmission infrastructure necessary to serve loads or if other resources become more economical, it may terminate those projects and, as alternatives, 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 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 purchase orders or construction contracts. Additionally, termination of a project carries with it the potential for impairment of the associated asset if regulators 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.

Changes in legislation, regulation, and government policy as a result of the 2016 U.S. presidential and congressional elections may have a material adverse effect on IDACORP’s and Idaho Power’s business in the future. The recent presidential and congressional elections in the United States could result in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy. While it is not possible to predict whether and when any such changes will occur, they could significantly impact IDACORP’s and Idaho Power’s businesses and the electric utility industry. Specific legislative and regulatory proposals discussed during and after the election that could have a material impact on IDACORP and Idaho Power include, but are not limited to, reform of the federal tax code; infrastructure renewal programs; and modifications to public company reporting requirements and environmental regulation. Further, the proposals could have an impact on the rate of growth of Idaho Power’s customers and their willingness to expand operations and increase electric service requirements. IDACORP and Idaho Power are unable to predict whether reform discussions will meaningfully change existing legislative and regulatory environments relevant to the companies, or if any such changes would have a net positive or negative impact on the companies. To the extent that such changes have a negative impact on the companies or Idaho Power’s customers, including as a result of related uncertainty, these changes may materially and adversely impact IDACORP’s and Idaho Power’s business, financial condition, results of operations, and cash flows.

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 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, renewable energy certificates, and health and safety are applicable to IDACORP's and Idaho Power's operations. Many of these laws and regulations 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. Idaho Power devotes significant resources to environmental monitoring, pollution control equipment, and mitigation projects to comply with existing and anticipated environmental regulations. However, it is possible that federal, state and local authorities could attempt to enforce more stringent standards, stricter regulation, and more expansive application of environmental regulations.

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 recently installed environmental control apparatus in two units of its co-owned Jim Bridger power plant at a cost of $100 million, excluding AFUDC. Due to uncertainties resulting from pending environmental regulation and the substantial estimated cost of installing similar controls on the remaining two units, Idaho Power is assessing whether to move forward with the remaining installations. Compliance with environmental regulations can significantly increase capital spending, operating costs and plant outages, and can negatively affect the affordability of Idaho Power's services for customers. Idaho Power cannot predict with certainty the amount and timing of all future expenditures necessary to comply with, or as a result of liabilities under, these environmental laws and regulations, although Idaho Power expects the expenditures will be substantial. In some cases, the costs to obtain permits and ensure facilities are in compliance may be prohibitively expensive. If the costs of compliance with 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. 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.

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Idaho Power is not guaranteed timely or full recovery through customer rates of costs associated with environmental regulations, environmental compliance, and clean-up of contamination, and regulators may not grant prior approval of cost recovery. For example, in 2013, the IPUC 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. 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.

In addition, some environmental regulations are currently subject to litigation and not yet final, such as the EPA’s proposed regulations to reduce CO ₂ emissions as described in Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters" in this report. As a result of this uncertainty, strategies to comply with the regulations, including available control technologies or other allowed compliance measures, are unpredictable and Idaho Power cannot provide any assurance regarding the potential impacts these regulations would have on Idaho Power's operations or 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 2016, 53 percent of Idaho Power's electric power generation was from hydroelectric facilities. Because of Idaho Power’s heavy reliance on hydroelectric generation, factors such as precipitation and snowpack, the timing of run-off, 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 aquifer by diverting surface water to porous locations and permitting it to sink into the aquifer is one approach to the over-appropriation dispute. Diversions from the Snake River for aquifer recharge or the loss of water rights 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 market power purchases; therefore, costs increase and opportunities for off-system sales are reduced, reducing revenues and potentially earnings. Through its power cost adjustment mechanisms, Idaho Power expects to recover most (but not all) of the increase in net power supply costs caused by lower hydroelectric generation. The timing of recovery of the increased costs, however, may not occur until the subsequent power cost adjustment year, adversely affecting cash flows and liquidity.

Obligations 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, including for the Hells Canyon Complex. 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 generation 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 a water temperature management apparatus which, if required to be installed, would involve substantial costs to construct, operate, and maintain. Idaho Power may be unable to recover in full or in a timely manner 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, whether a new multi-year license will ultimately be issued, and whether the IPUC or OPUC will allow recovery through rates of the substantial costs incurred in connection with the licensing process and subsequent compliance. 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.

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 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

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and demand such as weather conditions, fuel transportation availability, economic conditions, and changes in technology. Natural gas transportation to Idaho Power's three 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 on satisfactory terms, or at all. There also can be no assurance that counterparties to the natural gas or coal supply agreements will fulfill their obligations to supply natural gas or coal, and they may experience financial or technical problems that inhibit their ability to deliver natural gas or coal. 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 or timely recover these increased costs through rates, which may adversely affect IDACORP's and Idaho Power's financial condition and results of operations.

If the assumptions underlying coal mine reclamation at Bridger Coal Company and related forecast trust fund growth are materially inaccurate, Idaho Power’s costs could be greater than anticipated or be incurred sooner than anticipated . Bridger Coal Company, a subsidiary of Idaho Power, uses both surface and underground methods to mine coal to be used for power generation at the Jim Bridger power plant. The federal Surface Mining Control and Reclamation Act and state laws and regulations establish operational, reclamation, bonding, and closure obligations and standards for mining of coal. Bridger Coal Company’s estimate of reclamation liability and bonding obligations is reviewed periodically by Idaho Power’s management committee and by government regulators. Idaho Power funds a trust to cover such projected mine reclamation costs. The trust funds are invested in debt and equity securities and poor performance of these investments would reduce the amount of funds available for their intended purpose, which could require Idaho Power to make additional cash contributions. If actual costs related to those obligations exceed estimates, government regulations relating to those obligations change significantly or unexpected cash funding obligations are required, IDACORP’s and Idaho Power’s results of operations and financial condition could be adversely affected.

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, wildfires, 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. Further, the transmission system in Idaho Power's service area is constrained, limiting the ability to transmit electric energy within the service area and access electric energy from outside the service area 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.

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 and property damage, interest, and attorneys' fees. Fires alleged to have been caused by Idaho Power's system could also expose Idaho Power to claims for fire suppression costs and claims related to fires based on claims of negligence, trespass or otherwise. Idaho Power maintains insurance coverage for such operating and event risks, but insurance coverage is subject to the terms and limitations of the available policies and may not be sufficient to cover Idaho Power’s ultimate liability. Idaho Power is also subject to the risk that insurers and other parties will dispute, or be unable to perform, their obligations to Idaho Power with respect to such claims, which could have an adverse effect on IDACORP's and Idaho Power's financial condition and results of operations.

Volatility in the financial markets, failure of IDACORP or Idaho Power to satisfy conditions necessary for obtaining loans or issuing debt securities, and 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 . IDACORP and Idaho Power use credit facilities, commercial paper markets, and long-term debt as significant sources of liquidity and funding for operating and capital requirements and debt maturities not satisfied by operating cash flow. The credit facilities represent commitments by the participating banks to make loans and issue letters of credit. However, the obligation of the participating

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banks to make those loans and issue letters of credit is subject to specified conditions. Idaho Power's ability to issue long-term debt is also subject to a number of conditions included in an indenture, and Idaho Power's ability to issue long-term debt and commercial paper is subject to the availability of purchasers willing to purchase the securities under reasonable terms or at all. Because of these limitations, IDACORP and Idaho Power may be unable to issue commercial paper or short-term or long-term debt at reasonable interest rates and terms or at all. Also, while the credit facilities represent a contractual obligation to make loans, one or more of the participating banks may default on their obligations to make loans under, or may withdraw from, the credit facilities.

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, capital expenditures, and debt maturities. Without additional state regulatory approval, as of the date of this report the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million. Also, 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, and 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, results of operations, 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. 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 rate mechanisms, the effectiveness of management, resource risks and power supply costs, and other factors. 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, reduce the pool of potential lenders, increase borrowing costs under existing credit facilities, limit access to the commercial paper market, 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. If access to capital were to become significantly constrained or costs of capital increased significantly due to lowered credit ratings, prevailing industry conditions, regulatory constraints, the volatility of the capital markets or other factors, IDACORP's and Idaho Power's financial condition and results of operations could be adversely affected.

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 hedge transactions 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 used for hedging 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. Certain of Idaho Power's hedging and derivative agreements may result in the receipt of, or posting of, collateral with counterparties. Fluctuations in commodity prices that lead to the posting of collateral with counterparties negatively impact liquidity, and downgrades in Idaho Power's credit ratings may lead to additional collateral posting requirements. 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 and security standards issued by the North American Electric Reliability Corporation and enforced by the FERC. 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

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standard compliance issues to, the FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council. Potential monetary and non-monetary penalties for a violation of FERC 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.

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 has had an impact on the operation of Idaho Power's generation plants, system reliability, power supply costs, and the wholesale power markets in the Pacific Northwest. Idaho Power is generally obligated under federal law to purchase power from certain renewable energy projects, regardless of the then-current load demand, availability of lower cost generation resources, or wholesale energy market prices. This increases the likelihood and frequency that Idaho Power will be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources, which in turn increases power purchase costs and customer rates. Increases in customer rates could make self-generation more financially attractive for customers, which could result in reduced net load and shifts in customer costs. 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. If Idaho Power is unable to timely recover those costs through its power cost adjustment mechanisms or otherwise, those increased costs may negatively affect IDACORP's and Idaho Power's results of operations, financial condition, and cash flows.

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. As benefit costs continue to rise, there is no assurance that the state public utility commissions will continue to allow recovery. 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 means. 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.

IDACORP's and Idaho Power's activities are concentrated in one industry and in one region, which exposes it to risks from lack of diversification, regional economic conditions, and regional legislation and regulation. IDACORP and Idaho Power do not have diversified operations or sources of revenue. Idaho Power comprises the bulk of IDACORP's operations, and Idaho Power's business is concentrated solely in the electricity industry. Furthermore, Idaho Power's provision of electric service to retail customers is conducted exclusively in its southern Idaho and eastern Oregon service area. As a result, IDACORP's and

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Idaho Power's future performance will be affected by economic conditions, regulatory and legislative activity, and other events in its service area and in the electric power industry.

The impacts of a retiring 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’s operations require a skilled workforce to perform specialized utility functions. Many of these positions, such as linemen, grid operators, engineering and design personnel, and generation plant operators, require extensive, specialized training. Idaho Power has experienced in recent years an above-average number of employee retirements and expects the increased level of retirement of its skilled workforce and persons in key positions will continue in 2017 and in the near-term. At December 31, 2016, approximately 23 percent of Idaho Power's employees were eligible for regular or early retirement under Idaho Power's defined benefit pension plan. This will require Idaho Power to attract, train, and retain new employees to help prevent a loss of institutional knowledge and avoid a skills gap. The loss of skills and institutional knowledge of experienced employees and the costs associated with attracting, training, and retaining appropriately qualified employees to replace an aging and skilled workforce could have a negative effect on IDACORP's and Idaho Power's financial condition and results of operations.

IDACORP and Idaho Power are subject to costs and other effects of legal and regulatory proceedings, disputes, and claims . From time to time in the normal course of business, IDACORP and Idaho Power are subject to various lawsuits, regulatory proceedings, disputes, and claims that could result in adverse judgments or settlements, fines, penalties, injunctions, or other adverse consequences. These matters are subject to a number of uncertainties, and management is often unable to predict the outcome of such matters; resulting liabilities could exceed amounts currently reserved or insured against with respect to such matter. 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 operational practices and procedures, which could also have a negative effect on their financial positions and results of operations.

Acts or threats of terrorism, cyber attacks, data or physical 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, and public health and safety. 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 increase costs to protect, repair, and insure Idaho Power's assets and operate its business.

Federal regulators have stated that a number of organizations continue to seek opportunities to exploit potential vulnerabilities in the U.S. energy infrastructure and that those attacks have become increasingly sophisticated. Attacks on Idaho Power's infrastructure could result from acts of those organizations or other third parties as well as Idaho Power employees or contractors. At the same time, Idaho Power's energy infrastructure is becoming more reliant on network-based infrastructure. Idaho Power's operations require the continuous availability of information technology systems and network infrastructure, and in the normal course of business, Idaho Power collects sensitive and confidential customer and employee information and proprietary information of Idaho Power. Although Idaho Power actively monitors developments in cyber security, no security measures can completely shield Idaho Power's systems, infrastructure, and data from vulnerabilities to cyber attacks, intrusions, or other catastrophic events that could result in their failure or reduced functionality, and ultimately the potential loss of sensitive information or the loss of Idaho Power's ability to fulfill critical business functions and provide reliable electric power to customers. The loss of data could result in violations of privacy and other laws, financial loss to Idaho Power or to its customers, customer dissatisfaction, and significant litigation exposure, all of which could materially affect Idaho Power's financial condition and results of operations.

Changes in tax laws and regulations, or differing interpretation or enforcement of applicable laws by the U.S. 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. In recent years, tax settlements, as well as state regulatory mechanisms with tax-related provisions (such

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as Idaho Power's October 2014 regulatory settlement stipulation with the IPUC), has significantly impacted IDACORP's and Idaho Power's results of operations. The outcome of ongoing and future income tax proceedings, or the state public utility commissions' treatment of those tax outcomes, could differ materially from the amounts IDACORP and Idaho Power record prior to conclusion of those proceedings, and the difference could negatively affect IDACORP’s and Idaho Power’s earnings and cash flows. Further, in some instances the treatment from a ratemaking perspective of any tax benefits could be different than IDACORP or Idaho Power anticipate or request from applicable state regulatory commissions, which could have a negative effect on their financial condition and results of operations. In addition, Idaho Power uses flow-through accounting as described in Note 1 - "Summary of Significant Accounting Policies" to the consolidated financial statements included in this report, and potential changes in tax laws or interpretations may impact IDACORP's and Idaho Power's income taxes and reporting obligations differently than other companies.

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 SEC 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 FERC could significantly impact IDACORP's and Idaho Power's reported financial condition. Idaho Power meets conditions under generally accepted accounting principles (GAAP) 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, 2016 , the system also includes approximately 4,861 pole-miles of high-voltage transmission lines, 24 step-up transmission substations located at power plants, 24 transmission substations, 10 switching stations, 223 energized distribution substations (excluding mobile substations and dispatch centers), and approximately 27,263 pole-miles of distribution lines.

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

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Idaho Power's hydroelectric projects and other owned and co-owned generating facilities and their nameplate capacities are included in the table 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 one-third for Jim Bridger, 50 percent for North 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. Excluding Idaho Power's power generation facilities and substations, Idaho Power owns an additional 1,000,854 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.

Through Idaho Energy Resources Co., Idaho Power 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 17, 2017, there were 10,029 holders of record of IDACORP common stock and the closing stock price was $80.00 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 $ 105 million , $97 million , and $89 million in 2016 , 2015 , and 2014 , 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. The IDACORP board of directors has 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. IDACORP's dividends during 2016 were 53 percent of actual 2016 earnings. 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 2016 and 2015 as reported by the NYSE:



	2016						2015
Quarter	High		Low		Dividends paid per share		High		Low		Dividends paid per share
1st	$	74.96	$	65.03	$	0.51	$	70.48	$	59.21	$	0.47
2nd	81.36		69.83		0.51		64.22		55.40		0.47
3rd	83.40		75.14		0.51		64.94		55.96		0.47
4th	81.81		72.93		0.55		70.33		63.38		0.51

IDACORP did not repurchase any shares of its common stock during the fourth quarter of 2016.

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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 December 31, 2011, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.

Source: Bloomberg and EEI



	2011		2012		2013		2014		2015		2016
IDACORP	$	100.00	$	105.67	$	130.51	$	171.81	$	182.01	$	221.73
S&P 500	100.00		115.98		153.51		174.47		176.88		197.98
EEI Electric Utilities Index	100.00		102.09		115.37		148.72		142.92		167.84

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)
	2016			2015			2014			2013			2012
Operating revenues	$	1,262,020		$	1,270,289		$	1,282,524		$	1,246,214		$	1,080,662
Operating income	271,776			282,097			253,696			291,742			242,602
Net income attributable to IDACORP, Inc.	198,288			194,679			193,480			182,417			173,014
Diluted earnings per share	3.94			3.87			3.85			3.64			3.46
Dividends declared per share	2.08			1.92			1.76			1.57			1.37

Financial Condition:
Total assets ⁽¹⁾	$	6,289,897		$	6,023,314		$	5,701,037		$	5,347,380		$	5,274,147
Long-term debt (including current portion) ⁽¹⁾	$	1,745,678		$	1,726,474		$	1,599,686		$	1,599,139		$	1,520,553

Financial Statistics:
Times interest charges earned:
Before tax ⁽²⁾	3.54			3.61			3.38			3.87			3.41
After tax ⁽³⁾	3.15			3.12			3.19			3.06			3.02
Book value per share ⁽⁴⁾	$	42.74		$	40.88		$	38.85		$	36.84		$	34.73
Market-to-book ratio ⁽⁵⁾	188		%	166		%	170		%	141		%	125		%
Payout ratio ⁽⁶⁾	53		%	50		%	46		%	43		%	40		%
Return on year-end common equity ⁽⁷⁾	9.2		%	9.5		%	9.9		%	9.9		%	9.9		%

⁽¹⁾ Amounts in 2012-2014 adjusted to reflect IDACORP's 2015 adoption of Accounting Standards Update 2015-03, which required debt issuance costs be reported as reductions of long-term debt rather than as long-term assets on the consolidated balance sheets.
The financial statistics listed above are calculated in the following manner:
⁽²⁾ 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.
⁽³⁾ 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.
⁽⁴⁾ Total equity, excluding non-controlling interests, at the end of the year divided by shares outstanding at the end of the year.
⁽⁵⁾ 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 (4) above.
⁽⁶⁾ Dividends paid per common share divided by diluted earnings per share.
⁽⁷⁾ Net income attributable to IDACORP 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

In Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) in this report, the general financial condition and results of operations for IDACORP and its subsidiaries and Idaho Power and its subsidiary 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.

INTRODUCTION

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 whose rates and other matters are regulated by the IPUC, OPUC, and FERC. 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 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. Idaho Power’s rates are established through regulatory proceedings that affect its ability to recover its costs and the potential to earn a return on its investment.

Idaho Power is the parent of IERCo, a joint venturer in BCC, which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power. IDACORP’s other subsidiaries include 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 PURPA; and IDACORP Energy Services Co. (IESCo), 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.

EXECUTIVE OVERVIEW

Management's Outlook

Customer growth in Idaho Power's service area continues to benefit Idaho Power's revenues. To encourage continued 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 plans for infrastructure that will support anticipated growth and allow it to continue to provide reliable, fair-priced electric power to its customers. To that end, 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 permitting of 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's customers. To complement the regulatory framework, Idaho Power focuses 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. Idaho Power's base rates were most recently reset in 2012 through general rate cases in Idaho and Oregon. During 2017, Idaho Power will continue to assess the need to file a general rate case to reset base rates in the coming years in Idaho or Oregon.

Separately, during 2016, IDACORP continued to make meaningful progress toward its target dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings, which expanded on the progress made in previous years. From 2012 through 2016, IDACORP's board of directors approved a collective 83 percent increase in the quarterly dividend, from $0.30 to $0.55 per share.

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2016 Accomplishments and 2017 Initiatives

IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business. For the past several years, Idaho Power has been executing its three-part strategy of responsible planning, responsible development and protection of resources, and responsible energy use. This strategy is described in Part I, Item 1 - "Business" of this report. Examples of IDACORP's and Idaho Power's achievements and recognitions during 2016 under its three-part business strategy include:


•	IDACORP achieved net income growth for a ninth consecutive year;


•	IDACORP provided a 19 percent cumulative total shareholder return over the past three years, including share price appreciation and dividends paid, ranking in the 88th percentile among peers;


•	increased IDACORP's quarterly common stock dividend from $0.51 per share to $0.55 per share;


•	produced the best year of performance for Idaho Power's electric system reliability since formal measurement began in 2006;


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


•	made continued progress toward the permitting of the Boardman-to-Hemingway and Gateway West 500-kV transmission projects;


•	achieved Idaho Power's CO ₂ emissions intensity reduction goal;


•	earned the highest rolling 12-month customer relationship index score (Idaho Power's internal measure of customer satisfaction) ever recorded by the company; and


•	Idaho Power tied for 5th place in the annual "Best Energy Companies" rankings published by Public Utilities Fortnightly .

For 2017, IDACORP and Idaho Power have established a number of organizational initiatives, including the following:


•	continue to execute on the three core focuses for 2017—improving Idaho Power's core business, growing revenues, and enhancing the brand and positioning the company for the future;


•	continue to enhance and promote Idaho Power’s safety culture;


•	grow financial strength by supporting business development in Idaho Power's service area while actively managing costs;


•	continue upward progress within IDACORP’s target dividend payout ratio range;


•	pursue responsible investments that address customer growth while improving reliability, enhancing Idaho Power customers’ experience, increasing shareholder value, and managing carbon impacts; and


•	integrate new renewable generation resources into Idaho Power’s grid and continue progress toward participation in the Western EIM, anticipated to begin in the spring of 2018, which is expected to capture intra-hour market opportunities to help achieve greater reliability and improve system dispatch.

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 a number of factors, and the impact of those factors is discussed in more detail later in this MD&A. To provide context for the discussion elsewhere in this report, some of the more notable factors include the following:

•

Regulation of Rates and Cost Recovery: The price that Idaho Power is authorized to charge for its electric and transmission service is a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Those rates are established by state regulatory commissions and the FERC, and are intended to allow Idaho Power an opportunity to recover its expenses and earn a reasonable return on investment. Because of the significant impact of ratemaking decisions, and in pursuit of its goal of advancing a purposeful regulatory strategy, Idaho Power focuses on timely recovery of its costs through filings with the company's regulators, working to put in place innovative regulatory mechanisms, and on the prudent management of expenses and investments. Idaho Power has a regulatory settlement stipulation in Idaho that includes provisions for the accelerated amortization of certain tax credits to help achieve a minimum 9.5 percent return on year-end equity in the Idaho jurisdiction (Idaho ROE). During 2017, Idaho Power will continue to assess the need to file a general rate case to reset base rates.

•

Economic Conditions and Loads: Economic conditions impact consumer demand for electricity and revenues, 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. In recent years, Idaho Power has seen growth in the number of customers in its service area—in 2016, its customer count grew by 1.8 percent—and in employment in Idaho Power's service area, which grew by approximately 3.5 percent in 2016 based on Idaho Department of Labor preliminary December 2016 data. Idaho Power expects its number of customers to continue to

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increase in the foreseeable future. Idaho Power has in recent years supported State of Idaho-coordinated efforts to promote economic development with an emphasis on attracting industrial and commercial customers to its service area.

In August 2016, Idaho Power began preparing its 2017 IRP, Idaho Power's long-term forecast of loads and resources. The load forecast assumptions Idaho Power expects to use in the 2017 IRP are included in the table below. For comparison purposes, the analogous average annual growth rates used in the prior two IRPs are included.



	Forecast for 2016-2021 Period		20-Year Forecast
	Annual Growth Rate: Retail Sales (Billed MWh)	Annual Growth Rate: Annual Peak (Peak Demand)	Annual Growth Rate: Retail Sales (Billed MWh)	Annual Growth Rate: Annual Peak (Peak Demand)
2017 IRP	1.3%	1.4%	1.0%	1.4%
2015 IRP	1.1%	1.6%	1.2%	1.5%
2013 IRP	1.2%	1.6%	1.1%	1.4%

•

Rate Base Growth and Infrastructure Investment: As noted above, the rates established by the IPUC and OPUC are determined so as to provide an opportunity for Idaho Power to recover authorized operating expenses and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the IPUC and OPUC. In recent years, Idaho Power has been pursuing significant enhancements to its utility infrastructure, including major ongoing transmission projects such as the Boardman-to-Hemingway and Gateway West projects, 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, and the company is undertaking a significant relicensing effort for the Hells Canyon Complex (HCC), its largest hydroelectric generation resource. Idaho Power expects to include completed capital projects in its next general rate case or, in circumstances where appropriate, a single-issue rate case for individual projects with a significant capital cost. Depending on the outcome of the regulatory process and items such as the rate of return authorized by the IPUC and OPUC, this growth in rate base has the potential to increase Idaho Power's revenues and earnings.

•

Weather Conditions: Weather and agricultural growing conditions have a significant impact on Idaho Power's energy 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 extent 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. Much of the adverse or favorable impact of weather on sales of energy to residential and small commercial customers is mitigated through the Idaho FCA mechanism.

Further, as Idaho Power's hydroelectric facilities comprise nearly one-half of Idaho Power's nameplate generation capacity, precipitation levels impact the mix of Idaho Power's generation resources. When hydroelectric generation is reduced, Idaho Power must rely on more expensive generation sources and purchased power. When favorable hydroelectric generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydroelectric facility operators, lowering regional wholesale market prices and impacting the revenue Idaho Power receives from off-system sales of its excess power. Much of the adverse or favorable impact of this volatility is addressed through the Idaho and Oregon power cost adjustment mechanisms.

•

Mitigation of Impact of 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. Recently, low natural gas prices have made operation of Idaho Power's natural gas power plants more economical, resulting in increased operation of those plants and decreased operation of coal-fired plants. 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

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prices. The Idaho and Oregon power cost adjustment mechanisms mitigate in large part the potential adverse impacts of fluctuations in power supply costs to Idaho Power.

•

Changes in legislation, regulation, and government policy as a result of the 2016 U.S. presidential and congressional elections: The recent presidential and congressional elections in the United States could result in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy. While it is uncertain whether and when any such changes will occur, they could significantly impact IDACORP’s and Idaho Power’s businesses and the electric utility industry. Specific legislative and regulatory proposals discussed during and after the election that could have a material impact on IDACORP and Idaho Power include, but are not limited to, reform of the federal tax code; infrastructure renewal programs; and modifications to public company reporting requirements and environmental regulation.

•

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. Environmental laws and regulations, in particular, may 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, a decision driven in large part by the substantial cost of environmental controls required by existing regulations. Similarly, Idaho Power is assessing the early closure of the North Valmy coal-fired power plant, of which Idaho Power owns a 50-percent interest, and in October and November 2016 filed applications with the IPUC and OPUC, respectively, requesting accelerated depreciation of the facility. Idaho Power expects to spend a considerable amount on environmental compliance and controls in the next decade.

•

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 its hydroelectric projects. Also, Idaho Power is involved in renewing its long-term federal license for the HCC, its largest hydroelectric generation source. Given the number of parties and issues involved, Idaho Power's relicensing costs have been and will continue to be substantial. Idaho Power cannot currently determine the terms of, and costs associated with, any resulting long-term license.

Summary of 2016 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, 2016 , 2015 , and 2014 (in thousands, except earnings per share amounts):



	Year Ended December 31,
	2016		2015		2014
Idaho Power net income	$	189,242	$	190,983	$	189,387
Net income attributable to IDACORP, Inc.	$	198,288	$	194,679	$	193,480
Average outstanding shares – diluted (000’s)	50,373		50,292		50,199
IDACORP, Inc. earnings per diluted share	$	3.94	$	3.87	$	3.85

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The table below provides a reconciliation of net income attributable to IDACORP, Inc. for year ended December 31, 2016 from the year ended December 31, 2015 (items are in millions and are before tax unless otherwise noted):



Net income attributable to IDACORP, Inc. - December 31, 2015			$	194.7
Change in Idaho Power net income:
Customer growth, net of associated power supply costs	11.2
Usage per customer, net of associated power supply costs	(14.7	)
Other operating and maintenance expenses	(9.7	)
Depreciation expense	(5.6	)
Other changes in operating revenues and expenses, net	(1.5	)
Change in Idaho Power operating income prior to sharing mechanisms	(20.3	)
Change in operating income as a result of sharing mechanisms	3.2
Change in Idaho Power operating income	(17.1	)
Non-operating income and expenses	4.4
Income tax expense	11.0
Total decrease in Idaho Power net income			(1.7		)
IESCo income from legal settlement (net of tax)			3.7
Other changes (net of tax)			1.6
Net income attributable to IDACORP, Inc. - December 31, 2016			$	198.3

IDACORP's 2016 net income increased $3.6 million compared with 2015. While Idaho Power's 2016 net income was relatively flat, decreasing $1.7 million compared with 2015, net income from other subsidiaries increased IDACORP's net income by $5.3 million.

Continued customer growth at Idaho Power increased operating income by $11.2 million, which was more than offset by a $14.7 million decrease from lower usage per customer in 2016 compared with 2015. Winter temperatures in 2016 were slightly colder than 2015, but milder summer temperatures in 2016 led to lower sales volumes, revenues, and operating income. Other operating and maintenance (O&M) expenses were $9.7 million higher in 2016 compared with 2015, largely related to higher variable labor-related costs.

During 2015, Idaho Power recorded a total of $3.2 million as a provision against current revenue related to the October 2014 Idaho regulatory settlement stipulation that required sharing with Idaho customers of a portion of 2015 earnings that exceeded 10.0 percent. During 2016, no such sharing provision was recorded as Idaho Power's Idaho ROE did not exceed 10.0 percent. At December 31, 2016, the full $45 million of additional ADITC remains available for future use under the terms of the October 2014 Idaho regulatory settlement stipulation.

Idaho Power's income tax expense was lower in 2016 compared with 2015 due primarily to greater net flow-through income tax benefits, additional share-based compensation tax benefits related to the adoption of Accounting Standards Update 2016-09, and lower pretax income. These decreases were partially offset by a smaller flow-through benefit of a tax deductible make-whole premium that Idaho Power paid in connection with the early redemption of long-term debt in 2016 compared with the flow-through benefit of an early bond redemption in 2015.

IDACORP's 2016 net income also included a $3.7 million increase, net of tax, in IESCo's earnings, a result of a December 2016 settlement relating to the California energy market proceedings. Refer to Note 10 - “Contingencies” to the consolidated financial statements included in this report for additional information on the settlement. IDACORP also benefited from distributions related to fully-amortized affordable housing investments at IFS, which reduced IDACORP's income tax expense.

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 2016 are compared with 2015 and the results for 2015 are compared with 2014 .

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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,
	2016		2015		2014
General business sales	14,196		14,265		14,092
Off-system sales	1,186		1,254		2,220
Total energy sales	15,382		15,519		16,312
Hydroelectric generation	6,408		5,910		6,170
Coal generation	4,045		4,676		5,851
Natural gas and other generation	1,722		2,076		1,175
Total system generation	12,175		12,662		13,196
Purchased power	4,337		3,792		4,153
Line losses	(1,130	)	(935	)	(1,037	)
Total energy supply	15,382		15,519		16,312

Sales Volume and Generation: In 2016 , general business sales volumes decreased less than 1 percent compared with the prior year. Winter temperatures in 2016 were slightly colder than 2015, but milder summer temperatures in 2016 led to lower sales volumes. Also, a shorter irrigation season due to a later start in 2016 compared with 2015 resulted in lower usage per irrigation customer than during 2015.

Off-system sales volumes decreased 68 thousand MWh, or 5 percent , during 2016 compared with 2015. Low wholesale market prices reduced economic benefits of operating Idaho Power's non-hydroelectric generation facilities for off-system sales.

Favorable hydroelectric generating conditions from greater snowpack in the spring of 2016 compared with the spring of 2015 led to increased hydroelectric generation in 2016. Coal-fired generation decreased in 2016 compared with 2015 as low wholesale market prices led to an increase in purchased power.

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 power cost adjustment 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 (in thousands), MWh sales (in thousands), and number of customers for the last three years.



	Year Ended December 31,
	2016			2015			2014
Revenue
Residential	$	514,954		$	512,068		$	500,195
Commercial	302,650			306,178			299,462
Industrial	182,590			182,254			182,675
Irrigation	156,505			164,403			158,654
Total	1,156,699			1,164,903			1,140,986
Provision for sharing	—			(3,159		)	(7,999		)
Deferred revenue related to HCC relicensing AFUDC ⁽¹⁾	(10,706		)	(10,706		)	(10,706		)
Total general business revenues	$	1,145,993		$	1,151,038		$	1,122,281
Volume of Sales (MWh)
Residential	5,004			4,977			4,965
Commercial	3,999			4,045			3,944
Industrial	3,243			3,196			3,217
Irrigation	1,950			2,047			1,966
Total MWh sales	14,196			14,265			14,092
Number of customers at year-end
Residential	444,431			436,102			428,294
Commercial	69,344			68,352			67,522
Industrial	121			118			121
Irrigation	20,638			20,293			19,826
Total customers	534,534			524,865			515,763

⁽¹⁾ Idaho Power is collecting approximately $10.7 million annually in the Idaho jurisdiction for AFUDC on HCC construction work in progress, but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs are placed in service.

Changes in rates, changes in customer demand, and changes in FCA revenues are typically 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 influences on changes in customer demand for electricity are weather, economic conditions, and energy efficiency. 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 also affect sales to customers who use electricity to operate irrigation pumps. Boise, Idaho, weather-related information for the last three years is presented in the following table.



	Year Ended December 31,
	2016	2015	2014	Normal ⁽²⁾
Heating degree-days ⁽¹⁾	4,807	4,694	4,976	5,514
Cooling degree-days ⁽¹⁾	1,001	1,280	1,129	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 area, the greater Boise area has the majority of Idaho Power's customers.

⁽²⁾ Normal heating degree-days and cooling degree-days elements are, by convention, the arithmetic mean of the elements computed over 30 consecutive years. The annual normal amounts are the sum of the 12 monthly normal amounts. These normal amounts are computed by the National Oceanic and Atmospheric Administration.

Idaho Power's rate structure provides for higher rates during the summer when system loads are at their highest, and includes tiers such that rates increase as a customer's consumption level increases. These seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings.

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General Business Revenues - 2016 Compared with 2015 : General business revenue decreased $5.0 million in 2016 compared with 2015. The factors affecting general business revenues included the following:


•	Rates : Rate changes decreased general business revenue by $3.9 million for 2016 compared with 2015, primarily due to a decrease in the recovery of power cost adjustment amounts in 2016. The recovery of power cost adjustment amounts in rates has no effect on operating income as it is amortized into expense in the same period it is recovered through rates.


•	Customers : Customer growth of 1.8 percent increased general business revenue by $15.6 million in 2016 compared with 2015.

•

Usage : Lower usage (on a per customer basis), primarily by irrigation, commercial, and residential customers, decreased general business revenue by $21.3 million in 2016 compared with 2015. Winter temperatures in 2016 were slightly colder than 2015, but milder summer temperatures in 2016 compared with 2015 led to lower sales volumes. Also, a shorter irrigation season due to a later start in 2016 compared with 2015 resulted in lower usage per irrigation customer in 2016 than during 2015. Greater customer participation in energy efficiency programs also contributed to lower usage during 2016 compared with 2015.

•

Sharing : Idaho Power's sharing mechanism is associated with an 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. During 2015, Idaho Power recorded a total of $3.2 million as a provision against current revenue related to the sharing mechanism. In 2016, no such sharing provision was recorded as Idaho Power's Idaho ROE did not exceed 10.0 percent.


•	Idaho FCA Revenue : Partially offsetting lower usage per customer, the Idaho FCA mechanism increased revenues by $1.4 million in 2016 compared with 2015. Idaho Power accrued $30.3 million of Idaho FCA revenues in 2016, compared with $28.9 million in 2015.

General Business Revenues - 2015 Compared with 2014 : General business revenue increased $28.8 million in 2015 compared with 2014. The factors affecting general business revenues included the following:


•	Rates : Two rate changes impacted general business revenue—an Idaho PCA rate increase effective June 1, 2014, and Idaho PCA rate decrease effective June 1, 2015, both described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. Overall, rate changes combined to decrease general business revenue by $2.2 million in 2015.


•	Customers : Customer growth of 1.8 percent increased general business revenue by $14.1 million.


•	Usage : Lower usage per customer in 2015, primarily driven by the impact of more moderate winter weather on residential customer usage, as well as energy efficiency, decreased general business revenue by $0.7 million. Residential usage per customer was 1.4 percent lower in 2015.


•	Sharing : Revenue sharing of $3.2 million and $8.0 million were recorded in 2015 and 2014, respectively. This sharing resulted in a net increase to general business revenue of $4.8 million in 2015 compared with 2014.

•

Idaho FCA Revenue : FCA mechanism revenues increased $12.7 million compared with 2014, including the impacts of weather and of modifications made to the mechanism by the IPUC effective January 1, 2015. Idaho Power accrued $28.9 million of Idaho FCA revenues in 2015, compared with $16.2 million in 2014. The modifications to the FCA mechanism are described in more detail in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

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Off-System Sales : Off-system sales consist primarily of opportunity sales of surplus system energy. The following table presents Idaho Power’s off-system sales for the last three years (in thousands, except for MWh amounts):



	Year Ended December 31,
	2016		2015		2014
Revenue	$	25,205	$	30,887	$	77,165
MWh sold	1,186		1,254		2,220
Revenue per MWh	$	21.25	$	24.63	$	34.76

Off-System Sales - 2016 Compared with 2015 : Off-system sales revenue decreased by $5.7 million , or 18 percent . Off-system sales volumes decreased 5 percent in 2016 compared with the same periods in 2015 as low wholesale market prices reduced the economic benefits of operating Idaho Power's non-hydroelectric generation facilities for off-system sales. The average price of off-system sales for 2016 was 14 percent lower compared with 2015.

Off-System Sales - 2015 Compared with 2014 : Off-system sales revenue decreased by $46.3 million, or 60 percent, in 2015. Off-system sales volumes decreased 44 percent, as 2014 sales benefited from more favorable market conditions, at times, for selling power off-system. The average price of off-system sales transactions in 2015 was 29 percent lower than 2014, indicative of generally lower market prices in 2015. Decreases in output from hydroelectric resources and an increase in overall load due to customer growth also reduced the amount of surplus power available for sale off-system during 2015.

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



	Year Ended December 31,
	2016		2015		2014
Transmission services and other	$	54,401	$	55,048	$	52,051
Energy efficiency	33,754		30,532		27,154
Total other revenues	$	88,155	$	85,580	$	79,205

Other Revenues - 2016 Compared with 2015 : Other revenues increased $2.6 million , or 3 percent , in 2016 compared with 2015. Greater customer participation in energy efficiency programs increased revenue and corresponding expense in 2016 compared with 2015. 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. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from, or obligation to, customers. A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected. At December 31, 2016, Idaho Power's energy efficiency rider balances were a $5.6 million regulatory asset in the Oregon jurisdiction and a $10.7 million regulatory liability in the Idaho jurisdiction.

Other Revenues - 2015 Compared with 2014 : Other revenues increased $6.4 million, or 8 percent, in 2015. The increases in 2015 were primarily the result of increased electricity transmission (wheeling) volumes and greater customer participation in energy efficiency programs.

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Purchased Power : The table below presents Idaho Power’s purchased power expenses and volumes for the last three years (in thousands, except for MWh amounts):



	Year Ended December 31,
	2016		2015		2014
Expense
PURPA contracts	$	153,665	$	131,340	$	144,617
Other purchased power (including wheeling)	85,040		88,430		92,071
Demand response incentive payments	7,059		6,701		7,940
Total purchased power expense	$	245,764	$	226,471	$	244,628
MWh purchased
PURPA contracts	2,314		2,008		2,286
Other purchased power	2,023		1,784		1,867
Total MWh purchased	4,337		3,792		4,153
Cost per MWh from PURPA contracts	$	66.41	$	65.41	$	63.26
Cost per MWh from other purchased power	$	42.04	$	49.57	$	49.31
Weighted average - all sources (excluding demand response incentive payments)	$	55.04	$	57.96	$	56.99

Idaho Power is required by federal 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. The intermittent, non-dispatchable nature of the PURPA generation 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 its excess power in the wholesale power market at a significant loss. The other 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 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 power cost adjustment mechanisms.

Purchased Power - 2016 Compared with 2015 : Purchased power expense increased $19.3 million , or 9 percent , in 2016 . The increase was due primarily to increased volumes purchased from both PURPA and non-PURPA sources attributable largely to lower market prices at times that encouraged market purchases rather than operating some generating units. Volume increases were partially offset by lower non-PURPA wholesale market prices.

Purchased Power - 2015 Compared with 2014 : Purchased power expense decreased $18.2 million , or 7 percent , in 2015 . The decrease was due primarily to reduced volumes purchased from both PURPA and non-PURPA sources. Volume decreases were partially offset by increases in average prices of both PURPA and non-PURPA sources.

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Fuel Expense : The table below presents Idaho Power’s fuel expenses and thermal generation for the last three years (in thousands, except per MWh amounts):



	Year Ended December 31,
	2016		2015		2014
Expense
Coal ⁽¹⁾	$	137,689	$	131,286	$	156,172
Natural gas ⁽²⁾	41,802		54,945		45,069
Total fuel expense	$	179,491	$	186,231	$	201,241
MWh generated
Coal ⁽¹⁾	4,045		4,676		5,851
Natural gas ⁽²⁾	1,722		2,076		1,175
Total MWh generated	5,767		6,752		7,026
Cost per MWh - Coal	$	34.04	$	28.08	$	26.69
Cost per MWh - Natural gas	24.28		26.47		38.36
Weighted average, all sources	$	31.12	$	27.58	$	28.64

⁽¹⁾ 2015 excludes 147 MWh of generation from the Jim Bridger power plant for which costs were capitalized during feasibility testing of capital projects under contemplation.

⁽²⁾ Includes a negligible amount of expense and generation related to the Salmon diesel-fired generation plant.

The majority of the fuel for Idaho Power’s jointly-owned coal-fired plants is purchased through long-term contracts, including purchases from BCC, a one-third owned joint venture of IERCo. The price of coal from BCC is subject to fluctuations in mine operating expenses, geologic conditions, and production levels. BCC supplies up to two-thirds of the coal used by the Jim Bridger plant. Natural gas is mainly purchased on the regional wholesale spot market at published index prices. 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 - 2016 Compared with 2015 : In 2016 , fuel expense decreased $6.7 million , or 4 percent , compared with 2015 , due principally to decreased output from coal-fired plants and natural gas plants during 2016. Overall generation decreased 15 percent due to a change in resource mix resulting from increased purchase requirements from cogeneration and small power production (CSPP) projects, resource constraints at various generating locations, including Langley and Bridger, due to scheduled maintenance and other factors, and more open market purchases for economic reasons. The volume decreases were partially offset by higher coal prices due to higher mining costs at BCC. The higher mining costs resulted in part due to issues with underground mining equipment that is no longer in service.

Fuel Expense - 2015 Compared with 2014 : In 2015 , fuel expense decreased $15.0 million , or 7 percent , compared with 2014, due principally to decreased output from coal-fired plants during 2015 combined with lower regional natural gas prices for fuel used at the natural gas plants. Overall generation decreased 4 percent due to lower system loads and lower wholesale energy prices. The expense per MWh for natural gas decreased approximately 30 percent in 2015 compared with 2014. These lower natural gas prices led to a shift of generation from coal-fired plants to natural gas plants.

Power Cost Adjustment Mechanisms : Idaho Power's power supply costs (primarily purchased power and fuel expense, 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, 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 power cost adjustment 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 Idaho Power (5 percent), with the exception of PURPA power purchases and demand response program incentives, which are allocated 100 percent to customers. The Idaho deferral period, or PCA year, runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. Because of the power cost adjustment 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.

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The table that follows presents the components of the Idaho and Oregon power cost adjustment mechanisms for the last three years (in thousands).



	Year Ended December 31,
	2016			2015			2014
Idaho power supply cost deferrals	$	(43,841	)	$	(35,802	)	$	(48,104	)
Amortization of prior year authorized balances	38,511			52,568			70,339
Total power cost adjustment expense	$	(5,330	)	$	16,766		$	22,235

The power supply accruals (deferrals) represent the portion of the power supply cost fluctuations accrued (deferred) under the power cost adjustment mechanisms. When actual power supply costs are higher than the amount forecasted in power cost adjustment rates, which was the case for all periods presented, 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).

Power Cost Adjustment Mechanisms - 2016 Compared with 2015 : Actual net power supply cost deferrals increased in 2016 relative to 2015 , a change of $8.0 million —from $35.8 million to $43.8 million . The increase in the deferral is due in part to higher fuel costs related to coal and purchased power with less surplus sales than forecasted. The $38.5 million of amortization offsets the collection from customers of prior years' deferrals and was lower in 2016 as Idaho Power is amortizing a smaller deferral balance in the current year than the prior year.

Power Cost Adjustment Mechanisms - 2015 Compared with 2014 : Actual net power supply cost deferrals decreased in 2015 relative to 2014, a change of $12.3 million —from $48.1 million to $35.8 million . Power supply costs collected through base rates increased on June 1, 2015, resulting in less costs needing to be recovered through the power cost adjustment mechanisms since that time. The $52.6 million million of amortization offsets the collection from customers of prior years' deferrals.

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

O&M - 2016 Compared with 2015 : Other O&M expense increased by $9.7 million in 2016 compared with 2015 , an increase of 3 percent, due primarily to the following factors:


•	labor-related expenses increased $6.5 million, or 3 percent, in 2016 due to normal escalations in labor and benefits costs and higher variable employee costs;


•	scheduled maintenance at the Langley Gulch natural gas-fired generation plant increased O&M expenses $1.6 million; and


•	a $1.1 million increase primarily related to transmission agreements entered into in October 2015, which also resulted in a corresponding increase in other revenue.

O&M - 2015 Compared with 2014 : Other O&M expense decreased by $12.4 million in 2015 compared with 2014, a decrease of 3.5 percent, due to the following factors:


•	$16.7 million was recorded as additional pension expense in 2014 related to a December 2011 Idaho regulatory settlement agreement, which required sharing with Idaho customers of a portion of earnings in excess of a 10.0 percent Idaho ROE (thereby reducing customers' future pension obligations). There were no additional expenses related to the settlement agreement in 2015;


•	excluding the additional 2014 pension expense, labor-related expenses increased $2.1 million, or 1.1 percent, in 2015 due to normal escalations in labor and benefits costs; and


•	hydroelectric generation expenses increased $2.0 million, primarily due to increased repair costs and purchased services.

Income Taxes

IDACORP's and Idaho Power's 2016 income tax expense decreased $9.3 million and $11.0 million, respectively, when compared to 2015. The decrease was primarily due to greater net flow-through income tax benefits at Idaho Power, a tax benefit from the adoption of a new accounting standard for share-based compensation, distributions related to fully-amortized affordable housing investments at IDACORP, and lower Idaho Power pre-tax earnings in 2016.

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Income tax expense in 2015 increased significantly compared with 2014, principally as a result of a 2014 flow-through tax benefit related to the cumulative impact of tax accounting method changes for Idaho Power’s capitalized repairs deduction that did not recur in 2015. 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 continues to pursue 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 $287 million in 2016 , $284 million in 2015 , and $265 million in 2014 . Idaho Power expects these substantial capital expenditures to continue, with estimated total capital expenditures of approximately $1.5 billion expected over the period from 2017 through 2021 .

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. As of February 17, 2017 , IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:


•	their respective $100 million and $300 million revolving credit facilities;


•	IDACORP's shelf registration statement filed with the SEC on May 20, 2016, which may be used for the issuance of debt securities and common stock;


•	Idaho Power's shelf registration statement filed with the SEC on May 20, 2016, which may be used for the issuance of first mortgage bonds and debt securities; $500 million is available for issuance 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.

Based on planned capital expenditures and operating and maintenance expenses for 2017 , the companies believe they will be able to meet capital requirements and fund corporate expenses during 2017 with a combination of existing cash and operating cash flows generated by Idaho Power's utility business, together with proceeds from either draws on credit facilities or Idaho Power's issuance of debt securities. IDACORP and Idaho Power believe they could meet any short-term cash shortfall with existing credit facilities and expect to continue to manage short-term liquidity through commercial paper markets.

IDACORP and Idaho Power monitor capital markets with a view toward opportunistic debt and equity transactions, taking into account current and potential future long-term needs. As a result, IDACORP may issue debt securities or common stock, 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. To that end, on March 10, 2016, Idaho Power issued $120 million in principal amount of 4.05% first mortgage bonds, Series J, maturing on March 1, 2046. On April 11, 2016, Idaho Power redeemed, prior to maturity, its $100 million in principal amount of 6.15% first mortgage bonds, Series H, due April 2019. In accordance with the redemption provisions of the original terms of the notes, the redemption included payment by Idaho Power of a make-whole premium of $14 million. The make-whole premium resulted in a current income tax deduction, which under Idaho Power's regulatory flow-through tax accounting produced an income tax benefit of approximately $5.6 million recorded in the second quarter of 2016. Idaho Power also expects to receive an incremental net benefit to net income as a result of the lower interest rate of the notes issued in March 2016 compared with the interest rate associated with the redeemed notes. Idaho Power used a portion of the net proceeds of the March 2016 sale of first mortgage bonds, medium-term notes to effect the redemption. The companies do not expect to redeem any existing outstanding debt during 2017.

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, 2016 , IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:

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	IDACORP	Idaho Power
Debt	45%	47%
Equity	55%	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, income taxes, 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 2016 were $348 million and $311 million , respectively, a decrease of $5 million for IDACORP and $35 million decrease for Idaho Power when compared with 2015 . Significant items that affected the companies' operating cash flows in 2016 relative to 2015 were as follows:


•	changes in regulatory assets and liabilities, mostly related to the relative amounts of power supply and fixed costs deferred and collected under the Idaho rate mechanisms, decreased operating cash inflows by $19 million ;


•	changes in deferred taxes and in taxes accrued and receivable combined to decrease cash flows by $3 million and $34 million at IDACORP and Idaho Power, respectively;


•	Idaho Power received $24 million of distributions from IERCo's investment in BCC for 2016 , compared with $11 million in 2015 . Changes in distributions from year to year are primarily driven by changes in the timing of cash needs associated with BCC; and


•	comparative changes in working capital and other assets and liabilities increased cash flows by $7 million in 2016 compared with 2015, primarily related to changes in accounts payable due to timing of payments.

IDACORP's and Idaho Power's operating cash inflows in 2015 were $353 million and $346 million , respectively, a decrease of $11 million for IDACORP and a slight increase for Idaho Power when compared with 2014 . Significant items that affected the companies' operating cash flows in 2015 relative to 2014 were as follows:


•	changes in regulatory assets and liabilities, mostly related to the relative amounts of power supply and fixed costs deferred and collected under the Idaho rate mechanisms, decreased operating cash inflows by $18 million;


•	Idaho Power made $39 million of cash contributions to its defined benefit pension plan in 2015, compared with $30 million of cash contributions during 2014;


•	changes in deferred taxes and in taxes accrued and receivable combined to increase cash flows by $34 million and $50 million at IDACORP and Idaho Power, respectively; and


•	comparative changes in working capital balances due primarily to timing—principally related to a smaller decrease in accounts receivable in 2015 compared to the decrease in accounts receivable in 2014. Changes in accounts receivable balances reduced operating cash flows $16 million and $18 million for IDACORP and Idaho Power, respectively.

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 the allowance for borrowed funds used during construction, were $297 million , $294 million , and $274 million in 2016 , 2015 , and 2014 , 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. As discussed in "Capital Requirements" below, Idaho Power received $8 million and $11 million in 2016 and 2015 from Boardman-to-Hemingway project joint permitting participants relating to a portion of these construction expenditures.

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Idaho Power has a Rabbi trust designated to provide funding for obligations of its nonqualified defined benefit plans. In the Rabbi trust, Idaho Power purchased $15 million , $14 million , and $8 million of available-for-sale securities in 2016 , 2015 , and 2014 , respectively. In 2016 and 2015 , Idaho Power received $16 million and $34 million , respectively, of proceeds from the sales of available-for-sale securities and used $10 million and $30 million of the proceeds, respectively, to acquire company-owned life insurance.

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 2016 , 2015 , and 2014 :


•	on March 10, 2016, Idaho Power issued $120 million in principal amount of 4.05% first mortgage bonds Series J, maturing March 1, 2046;


•	on April 11, 2016, Idaho Power redeemed, prior to maturity, $100 million of its 6.15% first mortgage bonds, Series H, due April 1, 2019, and paid a related make-whole premium of $14 million;


•	on March 6, 2015, Idaho Power issued $250 million in principal amount of 3.65% first mortgage bonds, Series J, maturing on March 1, 2045;


•	on April 23, 2015, Idaho Power redeemed, prior to maturity, $120 million in principal amount of 6.025% first mortgage bonds, medium-term notes due July 2018, and paid a related make-whole premium of $18 million;


•	IDACORP and Idaho Power paid dividends of approximately $105 million , $97 million , and $88 million in 2016 , 2015 , and 2014 , respectively;


•	IDACORP's net change in commercial paper borrowings provided cash of $2 million in 2016 and used cash of $11 million and $23 million in 2015 and 2014 , respectively; and


•	Idaho Power borrowed $22 million in commercial paper in December 2016.

Financing Programs and Available Liquidity

IDACORP Equity Programs: In recent years IDACORP has entered into sales agency agreements under which IDACORP could offer and sell shares of its common stock from time to time through BNY Mellon Capital Markets, LLC as IDACORP's agent. The most recent agency agreement terminated in May 2016, but IDACORP may choose to enter into a new sales agency agreement in the future. On May 20, 2016, IDACORP filed a shelf registration statement with the SEC, which became effective upon filing, for the potential offer and sale of an unspecified amount of shares of common stock. As of the date of this report, IDACORP is assessing whether to execute a new sales agency agreement for the issuance and sale of common stock, as the company does not anticipate issuing any shares of its common stock outside of its equity or deferral compensation programs in 2017.

Since 2012, IDACORP has not used original issue shares of common stock for the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan or the Idaho Power Company Employee Savings Plan, but instead plan administrators have used market purchases of IDACORP common stock. However, IDACORP may determine at any time to use original issuances of common stock under those plans. As noted above, an important component of that determination will be IDACORP's and Idaho Power's capital structure.

Idaho Power First Mortgage Bonds : Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and Wyoming Public Service Commission (WPSC). In April and May 2016, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing Idaho Power to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is effective through May 31, 2019, subject to extension upon request to the IPUC. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum interest rate limit of seven percent.

On September 27, 2016, Idaho Power entered into a selling agency agreement with seven banks named in the agreement in connection with the potential issuance and sale from time to time of up to $500 million in aggregate principal amount of first mortgage bonds, secured medium term notes, Series K (Series K Notes), under Idaho Power’s Indenture of Mortgage and Deed

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of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). At the same time, Idaho Power entered into the Forty-eighth Supplemental Indenture, dated as of September 1, 2016, to the Indenture (Forty-eighth Supplemental Indenture). The Forty-eighth Supplemental Indenture provides for, among other items, (a) the issuance of up to $500 million in aggregate principal amount of Series K Notes pursuant to the Indenture and (b) the increase of the maximum amount of obligations to be secured by the Indenture to $2.5 billion (which maximum amount may be further increased or decreased by Idaho Power without the consent of the holders of first mortgage bonds). As of the date of this report, Idaho Power had not sold any first mortgage bonds, including Series K Notes, or debt securities under the selling agency agreement.

The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the Indenture. Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements.

The Indenture limits the amount of first mortgage bonds at any one time outstanding to $2.5 billion, and as a result the maximum amount of first mortgage bonds Idaho Power could issue as of December 31, 2016 , was limited to approximately $759 million. Idaho Power may increase the $2.5 billion limit on the maximum amount of first mortgage bonds outstanding by filing a supplemental indenture with the trustee as provided in the Indenture of Mortgage and Deed of Trust. Separately, the Indenture also limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture. As of December 31, 2016 , Idaho Power could issue approximately $1.7 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions.

Refer to Note 4 - “Long-Term Debt” to the consolidated financial statements included in this report for more information regarding long-term financing arrangements.

IDACORP and Idaho Power Credit Facilities : In November 2015, IDACORP and Idaho Power entered into credit agreements for $100 million and $300 million credit facilities, respectively. These facilities replaced IDACORP's and Idaho Power's existing Second Amended and Restated Credit Agreements, dated October 26, 2011, as amended. Each of the credit facilities may be used for general corporate purposes and commercial paper back-up. IDACORP's facility permits borrowings under a revolving line of credit of up to $100 million at any one time outstanding, including swingline loans not to exceed $10 million at any time and letters of credit not to exceed $50 million at any time. IDACORP's facility may be increased, subject to specified conditions, to $150 million . Idaho Power's facility permits borrowings through the issuance of loans and standby letters of credit of up to $300 million at any one time outstanding, including swingline loans not to exceed $30 million at any one time and letters of credit not to exceed $100 million at any time. Idaho Power's facility may be increased, subject to specified conditions, to $450 million . The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable margin, provided that the federal funds rate and LIBOR rate will not be less than zero percent. The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating, as set forth on a schedule to the credit agreements. The companies also pay a facility fee based on the respective company's credit rating for senior unsecured long-term debt securities.

Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less than 65 percent as of the end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, including, in some instances, indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). “Consolidated total capitalization” is calculated as the sum of all consolidated indebtedness, consolidated stockholders' equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At December 31, 2016 , the leverage ratios for IDACORP and Idaho Power were 45 percent and 47 percent , respectively. IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the credit facilities. There are additional covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary. At December 31, 2016 , IDACORP and Idaho Power believe they were in compliance with all facility covenants. Further, IDACORP and Idaho Power do not believe they will be in violation or breach of their respective debt covenants during 2017 .

The events of default under both facilities include, without limitation, non-payment of principal, interest, or fees; materially false representations or warranties; breach of covenants; bankruptcy or insolvency events; condemnation of property; cross-default to certain other indebtedness; failure to pay certain judgments; change of control; failure of IDACORP to own free and

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clear of liens the voting stock of Idaho Power; the occurrence of specified events or the incurring of specified liabilities relating to benefit plans; and the incurring of certain environmental liabilities, subject, in certain instances, to cure periods.

Upon any event of default relating to the voluntary or involuntary bankruptcy of IDACORP or Idaho Power or the appointment of a receiver, the obligations of the lenders to make loans under the applicable facility and to issue letters of credit will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding greater than 50 percent of the outstanding loans or greater than 50 percent of the aggregate commitments (required lenders) or the administrative agent with the consent of the required lenders may terminate or suspend the obligations of the lenders to make loans under the facility and to issue letters of credit under the facility and/or declare the obligations to be due and payable. During an event of default under the facilities, the lenders may, at their option, increase the applicable interest rates then in effect and the letter of credit fee by 2.0 percentage points per annum. A ratings downgrade would result in an increase in the cost of borrowing, but would not result in a default or acceleration of the debt under the facilities. However, if Idaho Power's ratings are downgraded below investment grade, Idaho Power must extend or renew its authority for borrowings under its IPUC and OPUC regulatory orders.

While the credit facilities provide for an original maturity date of November 6, 2020, the credit agreements grant IDACORP and Idaho Power the right to request up to two one-year extensions, in each case subject to certain conditions. On November 7, 2016, IDACORP and Idaho Power executed the first extension agreement with the consent of all the lenders, extending the maturity date under both credit agreements to November 5, 2021. No other terms of the credit facilities, including the amount of permitted borrowing under the credit agreements, were affected by the extensions.

Without additional approval from the IPUC, the OPUC, and the WPSC, the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million. Idaho Power has obtained approval of the state public utility commissions of Idaho, Oregon, and Wyoming for the issuance of short-term borrowings through November 2022.

IDACORP and Idaho Power Commercial Paper: IDACORP and Idaho Power have commercial paper programs under which they issue unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time not to exceed the available capacity under their respective credit facilities, described above. IDACORP's and Idaho Power's credit facilities are available to the companies to support borrowings under their commercial paper programs. The commercial paper issuances are used to provide an additional financing source for the companies' short-term liquidity needs. The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue. Individual instruments carry a fixed rate during their respective terms, although the interest rates are reflective of current market conditions, subjecting the companies to fluctuations in interest rates.

Available Short-Term Borrowing Liquidity

The following table outlines available short-term borrowing liquidity as of the dates specified:



	December 31, 2016					December 31, 2015
	IDACORP ⁽²⁾		Idaho Power			IDACORP ⁽²⁾			Idaho Power
Revolving credit facility	$	100,000	$	300,000		$	100,000		$	300,000
Commercial paper outstanding	—		(21,800		)	(20,000		)	—
Identified for other use ⁽¹⁾	—		(24,245		)	—			(24,245		)
Net balance available	$	100,000	$	253,955		$	80,000		$	275,755
⁽¹⁾ Port of Morrow and American Falls bonds that Idaho Power could be required to purchase prior to maturity under the optional or mandatory purchase provisions of the bonds, if the remarketing agent for the bonds were unable to sell the bonds to third parties.
⁽²⁾ Holding company only.

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The table below presents additional information about short-term commercial paper borrowing during the years ended December 31, 2016 and 2015 :



	December 31, 2016						December 31, 2015
	IDACORP ⁽¹⁾			Idaho Power			IDACORP ⁽¹⁾			Idaho Power
Commercial paper:
Year end:
Amount outstanding	$	—		$	21,800		$	20,000		$	—
Weighted average interest rate	—		%	1.13		%	0.88		%	—		%
Daily average amount outstanding during the year	$	15,692		$	438		$	22,054		$	—
Weighted average interest rate during the year	0.82		%	1.13		%	0.53		%	—		%
Maximum month-end balance	$	23,900		$	21,800		$	43,400		$	—
⁽¹⁾ Holding company only.

At February 17, 2017 , IDACORP had no loans outstanding under its credit facility and no commercial paper outstanding, and Idaho Power had no loans outstanding under its credit facility and no commercial paper outstanding.

Impact of Credit Ratings on Liquidity and Collateral Obligations

IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets, depends in part on their respective credit ratings. The following table outlines the ratings of Idaho Power’s and IDACORP’s securities, and the ratings outlook, by Moody’s Investors Service and Standard & Poor’s Ratings Services as of the date of this report:



	IDACORP	Idaho Power
Moody's Investors Service:
Rating Outlook	Stable	Stable
Long-Term Issuer Rating	Baa1	A3
First Mortgage Bonds	None	A1
Senior Secured Debt	None	A1
Commercial Paper	P-2	P-2
Standard & Poor's Rating Services:
Corporate Credit Rating	BBB	BBB
Rating Outlook	Stable	Stable
Short-Term Rating	A-2	A-2

These security ratings reflect the views of the ratings agencies. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating agency has its own methodology for assigning ratings and, accordingly, each rating should be evaluated independently of any other rating.

Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of December 31, 2016 , Idaho Power had posted no performance assurance collateral. Should Idaho Power experience a reduction in its credit rating on its unsecured debt to below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral, and counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of December 31, 2016 , the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $11.6 million. To minimize capital requirements, Idaho Power actively monitors its portfolio exposure and the potential exposure to additional requests for performance assurance collateral through sensitivity analysis.

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Capital Requirements

Idaho Power's construction expenditures, excluding AFUDC, were $287 million during the year ended December 31, 2016 . The table below presents Idaho Power's estimated cash requirements for construction, excluding AFUDC, for 2017 through 2021 (in millions of dollars). However, given the uncertainty associated with the timing of infrastructure projects and associated expenditures, actual expenditures and their timing could deviate substantially from those set forth in the table.



	2017		2018		2019-2021
Expected capital expenditures (excluding AFUDC)	$	290-300	$	285-295	$	900-950

Infrastructure Projects: A significant portion of expected capital expenditures included in the five-year forecast above relate to a large number of small projects as Idaho Power continues to add to its system to accommodate growth and improve reliability and operational effectiveness. These projects involve significant capital expenditures. Examples of anticipated system enhancements planned for 2017 through 2021 and estimated costs include the following:


•	$35-$65 million per year for transmission system projects other than the Boardman-to-Hemingway and Gateway West projects;


•	$75-$95 million per year for construction and replacement of distribution lines and stations, including replacement of underground distribution cables;


•	$25-$45 million per year for ongoing improvements and replacements at coal- and natural gas-fired plants;


•	$45-$65 million per year for hydroelectric plant improvement programs, including relicensing and mitigation costs; and


•	$45-$65 million per year for general plant improvements, such as land and buildings, vehicles, information technology, and communication equipment.

Other Major Infrastructure Projects: Idaho Power has recently completed or is engaged in the development of a number of significant projects and has entered into arrangements with third parties for joint development of infrastructure projects. The most notable projects are described below.

Jim Bridger Plant Selective Catalytic Reduction Equipment : Idaho Power and the plant co-owners recently completed installation of selective catalytic reduction (SCR) equipment to reduce nitrogen oxide (NO _x ) emissions at the Jim Bridger power plant, in order to comply with regional haze rules. The regional haze rules provided for installation of SCR on unit 3 and unit 4. The rules provide for an equivalent technology for NO _x reductions on unit 2 by 2021 and unit 1 by 2022. Idaho Power has expended $100 million, excluding AFUDC, on SCR installation at units 3 and 4 through December 31, 2016. The unit 3 SCR was operating as of November 2015, and the unit 4 SCR was operating as of November 2016. In light of the uncertainty resulting from pending environmental regulation and the substantial estimated cost of the SCR installation, as of the date of this report, Idaho Power is assessing whether to move forward with the installation of SCR on units 1 and 2 at the Jim Bridger power plant. The expected capital expenditures in the table above do not include any estimated expenditures relating to the installation of SCR on units 1 and 2.

Boardman-to-Hemingway Transmission Line : The Boardman-to-Hemingway line, a proposed 300-mile, 500-kV transmission project between a station near Boardman, Oregon, and the Hemingway station near Boise, Idaho, would provide transmission service to meet future resource needs. The Boardman-to-Hemingway line was included in the preferred resource portfolio in Idaho Power’s 2015 IRP. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration to pursue permitting of the project. The joint funding agreement provides that Idaho Power's interest in the permitting phase of the project would be approximately 21 percent, and that during future negotiations relating to construction of the transmission line Idaho Power would seek to retain that percentage interest in the completed project. Assuming both other participants fund their full share of the total cost of the permitting phase of the project, Idaho Power's estimated share of the cost of the permitting phase of the project is approximately $44 million, including Idaho Power's AFUDC. Total cost estimates for the project are between $1.0 billion and $1.2 billion, including AFUDC. This cost estimate excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above in addition to approximately $45 million of Idaho Power's share of costs related to early construction efforts primarily included in the periods 2019-2021. These preliminary estimates of Idaho Power’s share of early construction costs could significantly change as the construction timeline nears and as the project participants further align on future activities and estimates.

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Approximately $87 million has been expended on the Boardman-to-Hemingway project through December 31, 2016. Pursuant to the terms of the joint funding arrangements, Idaho Power has received approximately $42 million of that amount as reimbursement from the project participants as of December 31, 2016. Idaho Power has accrued in receivables approximately $16 million more that will be billed by Idaho Power in the future to the project participants for expenses Idaho Power has incurred, for a total amount reimbursable by joint permitting participants of $58 million. In addition to the $58 million amount, $6 million is subject to reimbursement at a later date from the joint permitting participants, assuming their continued participation in the project, for expenses Idaho Power incurred prior to execution of the joint funding arrangements. Joint permitting participants are obligated to reimburse Idaho Power for their share of any future project permitting expenditures incurred by Idaho Power. Idaho Power plans to seek recovery of its share of project costs through the regulatory process.

The permitting phase of the Boardman-to-Hemingway project is subject to federal review and approval by the U.S. Bureau of Land Management (BLM), the U.S. Forest Service, the Department of the Navy, the Army Corps of Engineers, and certain other federal agencies. The BLM, as the lead federal agency on the National Environmental Policy Act review, issued a final environmental impact statement (EIS) for the project on November 25, 2016. As of the date of this report, the BLM's schedule provides for the issuance of a record of decision in 2017. In the separate Oregon state permitting process, Idaho Power expects its amended preliminary application for site certificate to be deemed complete by the Oregon Department of Energy in 2017. Idaho Power is unable to determine an in-service date for the line but, given the status of ongoing permitting activities, expects the in-service date would be in 2023 or beyond.

Gateway West Transmission Line : Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a 500-kV transmission project between a station located near Douglas, Wyoming and the Hemingway station. In January 2012, Idaho Power and PacifiCorp entered a joint funding agreement for permitting of the project. Idaho Power's estimated cost for the permitting phase of the Gateway West project is approximately $60 million, including AFUDC. Idaho Power has expended approximately $32 million on the permitting phase of the project through December 31, 2016. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between $200 million and $400 million, including AFUDC. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above in addition to approximately $35 million of Idaho Power's share of costs related to early construction efforts primarily in the periods 2019-2021. These preliminary estimates of Idaho Power’s share of early construction costs could significantly change as the construction timeline nears and as the project participants further align on future activities and estimates.

The permitting phase of the Gateway West project is subject to review and approval of the BLM. The BLM released its record of decision in November 2013 for eight of the ten transmission line segments. On January 20, 2017, the BLM released its record of decision for the remaining two transmission line segments. In September 2016, the U.S. Department of Interior Board of Land Appeals affirmed the BLM's November 2013 record of decision, which was challenged by certain third-parties. In February 2017, the State of Idaho and others filed with the U.S. Department of Interior Board of Land Appeals notices of appeal and requests for a stay of the BLM’s record of decision.

Hells Canyon Complex Relicensing : The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 68 percent of Idaho Power's hydroelectric generating nameplate capacity and 32 percent of its total generating nameplate capacity. Idaho Power has been engaged in the process of obtaining from the FERC a new long-term license for the HCC. The past and anticipated future costs associated with obtaining a new long-term license for the HCC are significant. As of the date of this report, Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $25 million to $35 million until issuance of the license, which Idaho Power estimates will occur no earlier than 2021. Idaho Power expects that the annual capital expenditures and operating and maintenance expenses associated with compliance with the terms and conditions of the long-term license could also be substantial, but the company is currently unable to estimate those costs in light of the uncertainty surrounding the ultimate terms and conditions that may be included in the license. Idaho Power intends to seek recovery of those relicensing and compliance costs in rates through the regulatory process. Refer to "Regulatory Matters" in this MD&A for additional details relating to the relicensing process.

Environmental Regulation Costs: Idaho Power anticipates that it will incur significant expenditures for the installation of environmental controls at its coal-fired plants and for its hydroelectric relicensing efforts. The near-term cost estimates for environmental matters are summarized in Part I, Item 1 - "Business" of this report. The capital portion of these amounts is included in the Capital Requirements table above but does not include costs related to possible changes in current or new environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and emissions from coal-fired and gas-fired generation plants.

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Long-Term Resource Planning: The IPUC and OPUC require that Idaho Power prepare biennially an IRP. Idaho Power filed its most recent IRP in June 2015 and expects to file its 2017 IRP in June 2017. 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 2015 IRP included as near-term action items the continued permitting and planning for the Boardman-to-Hemingway transmission line and further investigation of the early retirement of the North Valmy power plant in collaboration with the plant's co-owner. Idaho Power filed applications with the IPUC and OPUC in October and November 2016, respectively, requesting accelerated depreciation of the North Valmy plant in connection with the potential early closure of the plant, which remain pending. The near-term action plan also included commencement of an economic evaluation of environmental control retrofits for units 1 and 2 at the Jim Bridger power plant. Additional information on Idaho Power's 2015 IRP and 2017 IRP is included in Part I, Item 1 - "Business - Resource Planning" in this report.

Defined Benefit Pension Plan Contributions and Recovery

Idaho Power contributed $40 million , $39 million , and $30 million to its defined benefit pension plan in 2016 , 2015 , and 2014 , respectively. Idaho Power estimates that it has no minimum contribution requirement for 2017 , though it plans to contribute between $20 million and $40 million to the pension plan during 2017 . Idaho Power's contributions are made in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions to mitigate the cost of being in an underfunded position. In 2017 and beyond, Idaho Power expects continuing significant contribution obligations under the pension plan. Refer to Note 11 - "Benefit Plans" to the consolidated financial statements included in this report and the section titled "Contractual Obligations" below in this MD&A for information relating to those obligations.

Idaho Power defers its Idaho-jurisdiction pension expense as a regulatory asset until recovered from Idaho customers. As of December 31, 2016 , Idaho Power's deferral balance associated with the Idaho jurisdiction was $105 million . Deferred pension costs are expected to be amortized to expense to match the revenues received when contributions are recovered through rates. Idaho Power only records a carrying charge on the unrecovered balance of cash contributions. The IPUC has authorized Idaho Power to recover and amortize $17 million of deferred pension costs annually, and has applied $68 million against the deferred amount under its Idaho sharing mechanisms since 2011. The primary impact of pension contributions is on the timing of cash flows, as cost recovery lags behind the timing of contributions.

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Contractual Obligations

The following table presents IDACORP’s and Idaho Power’s contractual cash obligations as of December 31, 2016, for the respective periods in which they are due:



	Payments Due by Period
	Total		2017		2018-2019		2020-2021		Thereafter
	(millions of dollars)
Long-term debt ⁽¹⁾	$	1,766	$	1	$	—	$	230	$	1,535
Future interest payments ⁽²⁾	1,464		82		163		151		1,068
Operating leases ⁽³⁾	48		3		8		8		29
Purchase obligations:
Cogeneration and small power production ⁽⁴⁾	4,309		229		465		465		3,150
Fuel supply agreements	206		57		31		17		101
Other ⁽⁴⁾	181		39		40		22		80
Pension and postretirement benefit plans ⁽⁵⁾	246		8		78		115		45
Other long-term liabilities	1		1		—		—		—
Total	$	8,221	$	420	$	785	$	1,008	$	6,008
⁽¹⁾ For additional information, see Note 4 – “Long-Term Debt” to the consolidated financial statements included in this report.
⁽²⁾ Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2016.
⁽³⁾ The operating leases include right-of-way easements. Approximately $13 million of the obligations included have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has been included in the table for presentation purposes.
⁽⁴⁾ Approximately $6 million of the amounts in cogeneration and small power production and $23 million of the amounts in other purchase obligations are contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has been included in the table for presentation purposes. Other purchase obligations also includes Idaho Power's estimated proportionate funding obligation for goods and services under non-fuel purchase agreements at its jointly-owned generation facilities. In some instances, Idaho Power is not a direct party to an underlying purchase agreement, but is obligated under the instruments governing the joint ventures to reimburse the co-owner for payments the co-owner makes pursuant to the purchase agreement. Those estimated amounts have been included in the table above.
⁽⁵⁾ Idaho Power estimates pension contributions based on actuarial data. As of the date of this report, Idaho Power cannot estimate pension contributions beyond 2021 with any level of precision, and amounts through 2021 are estimates only and are subject to change. For more information on pension and postretirement plans, refer to Note 11 – "Benefit Plans" to the consolidated financial statements included in this report.

Dividends

The amount and timing of dividends paid on IDACORP’s common stock are within the discretion of IDACORP’s board of directors. IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency considerations, 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.

IDACORP has a dividend policy 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 IDACORP's board of directors' 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 continue to take into account the factors above, among others. In September of 2014 , 2015 , and 2016 , IDACORP's board of directors voted to increase the quarterly dividend to $0.47 per share, $0.51 per share, and $0.55 per share of IDACORP common stock, respectively. IDACORP's dividends during 2016 were 53 percent of actual 2016 earnings.

For additional information relating to IDACORP and Idaho Power dividends, including restrictions on IDACORP’s and Idaho Power’s payment of dividends, see Note 6 – “Common Stock” to the consolidated financial statements included in this report.

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Contingencies and Proceedings

IDACORP and Idaho Power are involved in a number of litigation, alternative dispute resolution, and administrative proceedings, and are subject to claims and legal actions arising in the ordinary course of business, that could affect their future results of operations and financial condition. In many instances IDACORP and Idaho Power are unable to predict the outcomes of the matters or estimate the impact the proceedings may have on their financial positions, results of operations, or cash flows.

Idaho Power is also actively monitoring various environmental regulations that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to determine the financial impact of potential new regulations but does believe that future capital investment for infrastructure and modifications to its electric generating facilities to comply with these regulations could be significant.

Off-Balance Sheet Arrangements

Through a self-bonding mechanism, Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality, was $71 million at December 31, 2016 , representing IERCo's one-third share of BCC's total reclamation obligation of $212 million . BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2016 , the value of the reclamation trust fund totaled $78 million . During 2016 , the reclamation trust fund distributed approximately $6 million for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC adds a per-ton surcharge to coal sales. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.

REGULATORY MATTERS

Introduction

Idaho Power's regulatory strategy takes into consideration short-term and long-term needs for rate relief and involves several factors that can affect the timing of rate filings. These factors include, among others, in-service dates of major capital investments, the timing of changes in major revenue and expense items, and customer growth rates. Idaho Power's most recent general rate cases in Idaho and Oregon were filed during 2011, and Idaho Power filed a large single-issue rate case for the Langley Gulch power plant in Idaho and Oregon in 2012. These significant rate cases resulted in the resetting of base rates in both Idaho and Oregon during 2012. Idaho Power also reset its base-rate power supply expenses in the Idaho jurisdiction for purposes of updating the collection of costs through retail rates in 2014, but without a resulting net increase in rates. Between general rate cases, Idaho Power relies upon customer growth, power cost adjustment mechanisms, tariff riders, and other mechanisms to reduce the impact of regulatory lag, which refers to the period of time between making an investment or incurring an expense and recovering that investment or expense and earning a return. Management's regulatory focus in recent years has been largely on regulatory settlement stipulations and the design of rate mechanisms. During 2017, Idaho Power plans to continue to assess its need to file, and timing of, a general rate case in its two retail jurisdictions, based on its consideration of the factors described above.

Notable Retail Rate Changes in Idaho and Oregon

Included in the table that follows are notable regulatory developments during 2014, 2015, and 2016 that affected Idaho Power's results for the periods. Also refer to Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report for a description of regulatory mechanism and associated orders of the IPUC and OPUC, which should be read in conjunction with the discussion of regulatory matters in this MD&A.

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Description	Effective Date	Estimated Annualized Revenue Impact (millions) ⁽¹⁾
2014 Idaho FCA ⁽²⁾	6/1/2014		$	6
2014 Idaho PCA ⁽²⁾⁽³⁾	6/1/2014		(88		)
Transfer of power supply costs from the Idaho PCA mechanism to Idaho base rates ⁽⁴⁾	6/1/2014		99
2015 Idaho FCA ⁽²⁾	6/1/2015		2
2015 Idaho PCA ⁽²⁾⁽⁵⁾	6/1/2015		(12		)
2016 Idaho FCA ⁽²⁾	6/1/2016		11
2016 Idaho PCA ⁽²⁾⁽⁶⁾	6/1/2016		17

⁽¹⁾ The annual amount collected in rates is typically not recovered on a linear basis (i.e., 1/12th per month), and is instead recovered in proportion to general business sales volumes.
⁽²⁾ The rate changes for the Idaho PCA and FCA are applicable only for one-year periods. Similarly, a portion of the rate changes from the Oregon APCU are applicable only for one-year periods.
⁽³⁾ 2014 PCA rates reflect (a) the application of $20.0 million of surplus Idaho energy efficiency rider funds, (b) $8.0 million of customer revenue sharing for the year 2013 under a regulatory settlement agreement approved in December 2011, and (c) a $99.0 million shift in base net power supply expenses from recovery via the PCA mechanism to recovery through base rates.
⁽⁴⁾ See footnote (3) above. Approval of the transfer of collection of specified power supply costs from the Idaho PCA mechanism to Idaho base rates resulted in no net change in customer rates.
⁽⁵⁾ 2015 Idaho PCA rates reflect the application of (a) a customer rate credit of $8.0 million for sharing of revenues with customers for the year 2014 under the terms of a December 2011 settlement stipulation, (b) a $1.5 million customer benefit relating to a change to the PCA methodology described below, and (c) $4.0 million of surplus Idaho energy efficiency rider funds.
⁽⁶⁾ 2016 Idaho PCA rates reflect the application of (a) a customer rate credit of $3.2 million for sharing of revenues with customers for the year 2015 under the terms of an October 2014 settlement stipulation and (b) $4.0 million of surplus Idaho energy efficiency rider funds.

Idaho and Oregon General Rate Cases and Base Rate Adjustments

Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from the regulatory settlement of a general rate case filing Idaho Power made in 2011. In the general rate case, the IPUC issued an order approving a settlement stipulation that provided for an overall 7.86 percent authorized rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted in a $34.0 million overall increase in Idaho Power's annual Idaho-jurisdictional base rate revenues. Neither the IPUC's order nor the settlement stipulation specified an authorized rate of return on equity.

Effective March 1, 2012, Idaho Power implemented new Oregon base rates resulting from its receipt of an order from the OPUC approving a settlement stipulation in its general rate case proceedings that provided for a $1.8 million base rate revenue increase, a rate of return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction.

Idaho and Oregon base rates were subsequently adjusted again in 2012, in connection with Idaho Power's completion of the Langley Gulch power plant. In June 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdiction base rate revenues, effective July 1, 2012, for inclusion of the investment and associated costs of the plant in rates. The order also provided for a $335.9 million increase in Idaho rate base. On September 20, 2012, the OPUC issued an order approving a $3.0 million increase in annual Oregon jurisdiction base rate revenues, effective October 1, 2012, for inclusion of the investment and associated costs of the plant in Oregon rates.

In March 2014, the IPUC issued an order approving Idaho Power's application requesting an increase of approximately $106 million in the normalized or "base level" net power supply expense on a total-system basis to be used to update base rates and in the determination of the PCA rate that became effective June 1, 2014. Approval of the order removed the Idaho-jurisdictional portion of those expenses (approximately $99 million) from collection via the PCA mechanism and instead results in collecting that portion through base rates.

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Non-Base Rate Idaho Regulatory Settlement Stipulations

Settlement Stipulation for 2012 to 2014 : In December 2011, the IPUC issued an order, separate from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that allowed Idaho Power to, in certain circumstances, amortize additional ADITC if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 was less than 9.5 percent, to help achieve a 9.5 percent Idaho ROE for the applicable year. The more specific terms and conditions of the December 2011 Idaho settlement stipulation are described in Note 3 - "Regulatory Matters - Notable Idaho Regulatory Matters " to the consolidated financial statements included in this report. Under the December 2011 settlement stipulation, when Idaho Power's actual Idaho ROE for any of those years exceeded 10.0 percent, Idaho Power was required to share a portion of its Idaho-jurisdiction earnings with Idaho customers.

Settlement Stipulation for 2015 to 2019 : In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of the December 2011 settlement stipulation for the period from 2015 through 2019, or until the terms are otherwise modified or terminated by order of the IPUC or the full $45 million of additional ADITC contemplated by the settlement stipulation has been amortized. The more specific terms and conditions of the October 2014 settlement stipulation are described in Note 3 - "Regulatory Matters - Notable Idaho Regulatory Matters " to the consolidated financial statements included in this report. IDACORP and Idaho Power believe that the terms allowing amortization of additional ADITC in the October 2014 settlement stipulation provide the companies with a greater degree of earnings stability than would be possible without the terms of the stipulation in effect.

In 2016, Idaho Power's Idaho ROE was between 9.5 and 10.0 percent, and thus Idaho Power recorded no additional ADITC amortization and no provision for sharing with customers. Accordingly, at December 31, 2016, the full $45 million of additional ADITC remains available for future use under the terms of the settlement stipulation.

Idaho Power recorded the following for sharing with customers under the December 2011 and October 2014 Idaho Settlement Stipulations (in millions):



Year	Recorded as Refunds to Customers	Recorded as a Pre-tax Charge to Pension Expense
2016	$—	$—
2015	$3.2	$—
2014	$8.0	$16.7
2013	$7.6	$16.5
2012	$7.2	$14.6

Modifications to Idaho Annual Rate Adjustment Mechanisms

PCA Mechanism: In July 2014, the IPUC opened a docket pursuant to which Idaho Power, the IPUC Staff, and other interested parties evaluated Idaho Power's application of the true-up component of the PCA mechanism. The July 2014 docket arose from a prior order of the IPUC, which noted that the IPUC Staff believed that Idaho Power's application of the true-up component introduced a line-loss bias that inflated the true-up revenue that Idaho Power collects under the PCA. In May 2015, the IPUC approved a settlement stipulation that modified the calculation of the true-up component of the PCA mechanism. The mechanics of the PCA mechanism and the terms of the PCA settlement stipulation are described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

FCA Mechanism: Also in July 2014, the IPUC opened a docket to allow Idaho Power, the IPUC Staff, and other interested parties to further evaluate the IPUC Staff's concerns regarding the application of the FCA. Concerns cited included the application of weather-normalization, the customer count methodology, the rate adjustment cap, cross-subsidization issues, and whether the FCA is in fact effectively removing Idaho Power's disincentive to aggressively pursue energy efficiency programs.

The FCA 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 and linking it instead to a set amount per customer. Stated generally, under the FCA Idaho Power charges residential and small commercial customers when it recovers less "actual fixed costs per customer" than the base level of fixed costs that the IPUC authorized for recovery through rates in the last general rate case, and Idaho Power credits those customers when its "actual fixed costs per customer" recovered exceed that base level of fixed costs. The FCA is adjusted each year to collect, or refund, the difference between the authorized fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the year.

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In years when actual sales per customer are higher than weather-normalized sales due to high summer or low winter temperatures, Idaho Power expects that the new FCA methodology will be less favorable to Idaho Power than the prior methodology. Conversely, Idaho Power expects that the new FCA methodology will be more favorable to Idaho Power in years when actual sales per customer are lower than weather normalized sales due to cooler summer or warmer winter temperatures.

Deferred Net Power Supply Costs

Deferred power supply costs represent certain differences between Idaho Power's actual net power supply costs and the costs included in its retail rates, the latter being based on annual forecasts of power supply costs. Deferred power supply costs are recorded on the balance sheets for future recovery or refund through customer rates. Idaho Power's power cost adjustment mechanisms in its Idaho and Oregon jurisdictions provide for annual adjustments to the rates charged to retail customers. The power cost adjustment mechanisms and associated financial impacts are described in "Results of Operations" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Factors that have influenced power cost adjustment rate changes in recent years include year-to-year volatility in hydroelectric generation conditions, market energy prices and the volume of off-system sales, power purchase costs from renewable energy projects, and revenue sharing under Idaho regulatory settlement stipulations. From year to year, these factors can vary significantly, which can result in significant accruals and deferrals under the power cost adjustment mechanisms. The power cost adjustment rate changes reflected in the table under the heading "Notable Retail Rate Changes in Idaho and Oregon" are illustrative of the volatility of net power supply costs and the impact on power cost adjustment rates.

As noted above under the heading "Idaho and Oregon General Rate Cases and Base Rate Adjustments," in light of the existence of permanent increases in power supply costs, in March 2014 the IPUC issued an order approving Idaho Power's application requesting recovery of a portion of its ongoing power supply costs through base rates rather than through the PCA mechanism.

The following table summarizes the change in deferred net power supply costs over the prior two years.



	Idaho			Oregon ⁽¹⁾			Total
Balance at December 31, 2014	$	54,512		$	4,677		$	59,189
Current period net power supply costs deferred	35,802			—			35,802
Revenue sharing	(7,999		)	—			(7,999		)
Energy efficiency rider funds	(4,000		)	—			(4,000		)
Prior amounts recovered through rates	(32,519		)	(2,294		)	(34,813		)
SO ₂ allowance and renewable energy certificate (REC) sales	(1,575		)	(70		)	(1,645		)
Interest and other	335			351			686
Balance at December 31, 2015	44,556			2,664			47,220
Current period net power supply costs deferred	43,841			—			43,841
Revenue sharing	(3,171		)	—			(3,171		)
Energy efficiency rider funds	(3,970		)	—			(3,970		)
Prior amounts recovered through rates	(27,316		)	(2,502		)	(29,818		)
SO ₂ allowance and renewable energy certificate (REC) sales	(874		)	(41		)	(915		)
Interest and other	376			307			683
Balance at December 31, 2016	$	53,442		$	428		$	53,870
⁽¹⁾ Oregon power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon revenue per year (approximately $3 million). Deferrals are amortized sequentially.

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Anticipated Participation in Western Energy Imbalance Market

In January 2017, the IPUC issued an order authorizing Idaho Power’s requested deferral accounting treatment for costs associated with joining the Western EIM. Idaho Power can defer costs incurred until the earlier of when Idaho Power requests recovery of the costs and the deferral balance or the end of 2018. Idaho Power anticipates that it will begin participating in the Western EIM in the spring of 2018. The Western EIM is intended to reduce the power supply 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. Refer to Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report for additional information relating to Idaho Power's anticipated participation in the Western EIM.

Open Access Transmission Tariff Rate Proceedings

Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on financial and operational data Idaho Power files with the FERC. In August 2016, Idaho Power filed its 2016 final transmission rate with the FERC, reflecting a transmission rate of $25.52 per kW-year, to be effective for the period from October 1, 2016, to September 30, 2017. Idaho Power's final rate was based on a net annual transmission revenue requirement of $127.4 million. Historic OATT rate information is included in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Transmission Revenues Associated with Asset Exchange Transaction

Effective in October 2015, Idaho Power and PacifiCorp each transferred to the other certain interests in transmission-related equipment. In connection with that transaction, the companies terminated or amended a number of long-term agreements between Idaho Power and PacifiCorp related to the ownership and operation of transmission-related equipment and transmission services. In 2014, Idaho Power collected approximately $8 million in transmission revenues under long-term transmission agreements that were terminated in connection with the asset exchange transaction. As a result of the transaction and termination of those long-term transmission agreements, Idaho Power's OATT rate increased; however, in accordance with a FERC order, the current formula rate methodology will phase in the increase over a two-year period from October 1, 2016 through September 30, 2018.

In compliance with the IPUC's order approving the asset exchange transaction, Idaho Power submitted to the IPUC a request for verification that its regulatory accounting method reflecting a symmetrical tracking of changes in transmission revenues resulting specifically from the asset exchange with PacifiCorp complies with the IPUC’s order. As an alternative proposed by Idaho Power to its symmetrical tracking, in August 2016, the IPUC ordered that any changes in transmission revenues resulting from the asset exchange will be addressed, prospectively, in Idaho Power's next general rate case.

Depreciation Rate Requests

In October and November 2016, Idaho Power filed applications with the IPUC and OPUC, respectively, requesting authorization to (a) accelerate depreciation for the North Valmy coal-fired power plant, to allow the plant to be fully depreciated by December 31, 2025, (b) establish a balancing account to track the incremental costs and benefits associated with the accelerated depreciation date, and (c) adjust customer rates to recover the associated incremental annual levelized revenue requirement in an aggregate amount of $29.6 million. Idaho Power also filed applications with the IPUC and OPUC requesting approval to institute revised depreciation rates for Idaho Power's other electric plant-in-service and adjust base rates by an aggregate of $7.4 million to reflect the revised depreciation rates applied to electric plant-in-service balances subject to the most recent general rate case. The depreciation filings are described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Relicensing of Hydroelectric Projects

Overview: Idaho Power, like other utilities that operate non-federal hydroelectric projects on qualified waterways, obtains licenses for its hydroelectric projects from the FERC. These licenses have a term of 30 to 50 years depending on the size, complexity, and cost of the project. The expiration dates for the FERC licenses for each of the facilities are included in Part I - Item 2 - "Properties" in this report. Costs for the relicensing of Idaho Power's hydroelectric projects are recorded in construction work in progress until a new multi-year license is issued by the FERC, at which time the charges are transferred to electric plant in service. Idaho Power will submit relicensing costs and costs related to new licenses to regulators for recovery

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through the ratemaking process and, in December 2016, submitted a request for a determination of prudency, which is described below. As of December 31, 2016, relicensing costs of $249 million for the HCC, Idaho Power's largest hydroelectric complex and a major relicensing effort, were included in construction work in progress. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $6.5 million annually ($10.7 million when grossed-up for the effect of income taxes) of AFUDC relating to the HCC relicensing project. Collecting these amounts now will reduce the amount collected in the future once the HCC relicensing costs are approved for recovery in base rates. As of December 31, 2016, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $103 million. In addition to the discussion below, refer to "Environmental Matters" in this MD&A for a discussion of environmental compliance under FERC licenses for Idaho Power's hydroelectric generating plants.

Hells Canyon Complex: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 68 percent of Idaho Power's hydroelectric generating nameplate capacity and 32 percent of its total generating nameplate capacity. In July 2003, Idaho Power filed an application with the FERC for a new license in anticipation of the July 2005 expiration of the then-existing license. Since the expiration of that license, Idaho Power has been operating the project under annual licenses issued by the FERC. In December 2004, Idaho Power and eleven other parties, including National Marine Fisheries Service (NMFS) and U.S. Fish and Wildlife Service (USFWS), involved in the HCC relicensing process entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on Endangered Species Act (ESA) listed species pending the relicensing of the project. In August 2007, the FERC Staff issued a final EIS for the HCC, which the FERC will use to determine whether, and under what conditions, to issue a new license for the project. The purpose of the final EIS is to inform the FERC, federal and state agencies, Native American tribes, and the public about the environmental effects of Idaho Power's operation of the HCC. Certain portions of the final EIS involve issues that may be influenced by water quality certifications for the project under Section 401 of the Clean Water Act (CWA) and formal consultations under the ESA, which remain unresolved.

In connection with its relicensing efforts, Idaho Power has filed water quality certification applications, required under Section 401 of the CWA, with the states of Idaho and Oregon requesting that each state certify that any discharges from the project comply with applicable state water quality standards. Section 401 of the CWA requires that a state either approve or deny a Section 401 water quality certification application within one year of the filing of the application or the state may be considered to have waived its certification authority under the CWA. As a consequence, Idaho Power has been filing and withdrawing its Section 401 certification applications with Oregon and Idaho on an annual basis while it has been working with the states to identify measures that will provide reasonable assurance that discharges from the HCC will adequately address applicable water quality standards. In the 2016 Section 401 certification application process, Oregon required Idaho Power to comply with fish passage and reintroduction conditions. Idaho's water quality certification, however, specifically forbids Idaho Power from reintroducing certain fish protected under the ESA, into Idaho's waters. On November 30, 2016, Idaho Power filed a petition with the FERC requesting that the FERC resolve the conflict between Oregon's and Idaho's conditions and declare that the FPA pre-empts the Oregon state law. In January 2017, the FERC issued an order denying Idaho Power’s petition, stating that the petition for a declaratory order was premature, cannot realistically be considered separately from the issue of the states’ certification authority under the CWA Section 401, and raises issues that are beyond the FERC’s authority to decide. As of the date of this report, Idaho Power is considering other actions it may take to obtain a resolution of the issue.

In September 2007, in connection with the issuance of its final EIS, the FERC notified the NMFS and the USFWS of its determination that the licensing of the HCC was likely to adversely affect ESA-listed species, including the bull trout and fall Chinook salmon and steelhead, under the NMFS's and USFWS's jurisdiction and requested that the NMFS and USFWS initiate formal consultation under Section 7 of the ESA on the licensing of the HCC. Each of the NMFS and USFWS responded to the FERC that the conditions relating to the licensing of the HCC were not fully described or developed in the final EIS as the measures to address the water quality effects of the project were yet to be fully defined by the Section 401 certification process. The NMFS and USFWS therefore recommended that formal consultation under the ESA be delayed until the Section 401 certification process is completed.

Idaho Power continues to work with Idaho and Oregon in the development of measures to provide reasonable assurance that any discharges from the HCC will comply with applicable state water quality standards so that appropriate water quality certifications can be issued for the project, and continues to cooperate with the USFWS, NMFS, and the FERC in an effort to address ESA concerns. Idaho Power has begun the process for construction of new aerated runners at the Brownlee project (part of the HCC) at an estimated cost of $50 million. The first of four units was installed in 2016 and Idaho Power plans to install one unit in each year from 2017 through 2019. Other measures that have been proposed or considered have included modification of spillways at two dams in the HCC to address total dissolved gas issues, and upstream watershed improvements or the installation of a temperature control structure to address water temperatures during a small portion of the year. If Idaho Power is required to take these or other additional measures to satisfy relicensing requirements, it could add substantially to

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project costs. Idaho Power continues to work with the Oregon and Idaho Departments of Environmental Quality on the water quality certification issue and the water quality measures that will be required to obtain 401 certification.

As of the date of this report, Idaho Power is unable to predict the timing of issuance by the FERC of any license order or the ultimate capital investment and ongoing operating and maintenance costs Idaho Power will incur in complying with any new license. However, as of the date of this report, Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $25 million to $35 million until issuance of the license, which Idaho Power estimates will occur no earlier than 2021. In light of the costs incurred and the considerable passage of time, in December 2016, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensing of the HCC were prudently incurred, and thus eligible for future inclusion in retail rates.

Renewable Energy Standards and Contracts

Renewable Portfolio Standards: Numerous proponents have introduced legislation in the U.S. Congress that would require electric utilities to obtain a specified percentage of their electricity from renewable sources, commonly referred to as a "renewable portfolio standard" or "RPS." However, as of the date of this report no federal or State of Idaho RPS is in effect. Idaho Power will be required to comply with a five- or ten-percent RPS in Oregon beginning in 2025 (depending on loads at that time), and Idaho Power expects to meet either RPS requirement with Renewable Energy Certificates (REC) obtained from the purchase of power from the Elkhorn Valley wind project.

Pursuant to an IPUC order, Idaho Power is selling its near-term RECs and returning to customers their share (shared 95% with customers in the Idaho jurisdiction) of those proceeds through the PCA. For the years ended December 31, 2016, 2015, and 2014, Idaho Power's REC sales totaled $1.0 million, $1.8 million, and $3.2 million, respectively. The comparative decrease in REC sales resulted primarily from the elimination of a REC purchase and sale agreement with a third party.

Were Idaho Power to be subject to additional RPS legislation, it may cease in full or in part the sale of RECs it receives, seek to obtain RECs from additional projects, generate RECs from any REC-generating facilities it owns or may be required to construct in light of an RPS, or purchase RECs in the market. Historically, Idaho Power has generally not received the RECs associated with PURPA projects. However, an order issued by the IPUC in December 2012, described below, provides that Idaho Power will own a portion of the RECs generated by some PURPA projects. The required purchase of additional RECs to meet RPS requirements would increase Idaho Power's costs, which Idaho Power expects would be wholly or largely passed on to customers through rates and the power cost adjustment mechanisms.

Renewable and Other Energy Contracts: Idaho Power has contracts for the purchase of power from both CSPP projects under PURPA and non-CSPP renewable generation sources such as biomass, wind, solar, small hydroelectric projects, and two geothermal projects. Idaho Power purchases wind power from both CSPP and non-CSPP facilities, including its largest non-CSPP wind power project—the Elkhorn Valley wind project with a 101-MW nameplate capacity. As of December 31, 2016, Idaho Power had contracts to purchase energy from 117 on-line CSPP projects, twelve additional projects expected to come on-line in 2017, and three projects expected to come on-line in 2019. The following table sets forth, as of December 31, 2016, the resource type and nameplate capacity of Idaho Power's signed CSPP and non-CSPP related agreements. These agreements have original contract terms ranging from one to 35 years.

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Resource Type	Total On-line (MW)	Began operating during 2016 (MW)	Under Contract but not yet On-line (MW)	Total Projects under Contract (MW)
CSPP:
Wind	577	—	50	627
Solar	170	170	129	299
Hydroelectric	148	1	8	156
Other	50	—	—	50
Total CSPP	945	171	187	1,132
Non-CSPP:
Wind	101	—	—	101
Geothermal	35	—	—	35
Total non-CSPP	136	—	—	136

All but three of the projects not yet on-line are expected to be on-line no later than mid-year 2017 (three solar projects are scheduled to be on-line in 2019).

In April 2015, Idaho Power made filings with the OPUC requesting, among other things, a reduction in the term of standard PURPA power purchase agreements from 20 years to two years for projects above 100 kW, in a manner consistent with its Idaho jurisdiction where the IPUC reduced the length of PURPA contracts that involve avoided-cost-based pricing to two years, and a temporary suspension of Idaho Power's obligation to enter into new fixed-price standard PURPA agreements during the pendency of the proceedings. In March 2016, the OPUC issued an order permanently reducing the eligibility cap for solar project standard contracts to 3 MW, with all other resource types retaining an eligibility cap of 10 MW. In its order, the OPUC retained the requirement for up to 20-year contract lengths for Oregon jurisdictional projects, comprised of 15 years of fixed prices and five years of market index prices.

In June 2016, the FERC held a technical conference on implementation issues under PURPA, including the mandatory power purchase obligation and the methods for determining avoided costs for those purchases. The conference also involved a discussion of PURPA project siting issues and minimum contract term lengths. In September 2016, the FERC filed a notice inviting post-technical conference comments on (1) the use of the "one-mile rule" to determine the size of an entity seeking certification as a small power production qualifying facility and (2) minimum standards for PURPA-purchase contracts. In November 2016, Idaho Power provided comments to the FERC specifically addressing Idaho Power’s position regarding the two items of which the FERC invited comments. Idaho Power is unable to predict what policy or rulemaking actions or proceedings, if any, on PURPA-related issues will result from the technical conference.

ENVIRONMENTAL MATTERS

Overview

Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the CAA, the CWA, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the ESA, among other laws. These laws are administered by a number of federal, state, and local agencies. In addition to imposing continuing compliance obligations and associated costs, these laws and regulations provide authority to regulators to levy substantial penalties for noncompliance, injunctive relief, and other sanctions. Idaho Power's three co-owned coal-fired power plants and three natural gas-fired combustion turbine power plants are subject to many of these regulations. Idaho Power's 17 hydroelectric projects are also further subject to a number of water discharge standards and other environmental requirements.

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Compliance with current and future environmental laws and regulations may:


•	increase the operating costs of generating plants;


•	increase the construction costs and lead time for new facilities;


•	require the modification of existing generating plants, which could result in additional costs;


•	require the curtailment or shut-down of existing generating plants; or


•	reduce the output from current generating facilities.

Current and future environmental laws and regulations will increase the cost of operating fossil fuel-fired generation plants and constructing new generation and transmission facilities, in large part through the substantial cost of permitting activities and the required installation of additional pollution control devices. In many parts of the United States, some higher-cost, high-emission coal-fired plants have ceased operation or the plant owners have announced a near-term cessation of operation, as the cost of compliance makes the plants uneconomical to operate. The decision to agree to cease operation of the Boardman coal-fired plant, in which Idaho Power owns a 10 percent interest, by the end of 2020, was based in part on the significant future cost of compliance with environmental laws and regulations. Idaho Power filed an application with the IPUC and OPUC in October and November 2016, respectively, requesting accelerated depreciation of the North Valmy plant in connection with the potential early closure of the plant. Additionally, in light of the uncertainty resulting from pending environmental regulation and the substantial estimated cost of SCR controls, Idaho Power is assessing whether to move forward with the installation of SCR on units 1 and 2 at the Jim Bridger coal-fired power plant.

In addition to increasing costs generally, these environmental laws and regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and early plant retirements cannot be fully recovered in rates on a timely basis. Part I, Item 1 - “Business - Utility Operations - Environmental Regulation and Costs ” in this report includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 2017 to 2019. Given the uncertainty of future environmental regulations and technological advances, Idaho Power is unable to predict its environmental-related expenditures beyond 2019, though they could be substantial. Furthermore, the recent presidential and congressional elections in the United States could result in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy regarding environmental matters. Idaho Power may delay making operational changes or environmental-related expenditures while such changes are pending to avoid implementing uncertain laws, rules, and policies.

Endangered Species Act Matters

Overview: The listing of a species of fish, wildlife, or plants as threatened or endangered under the ESA may have an adverse impact on Idaho Power's ability to construct generation, transmission, or distribution facilities or relicense or operate its hydroelectric facilities. When a species is added to the federal list of threatened and endangered species, it is protected from “take,” which is defined to include harming the species. The ESA directs that, concurrent with a designation of a threatened or endangered species, and where prudent and determinable, the applicable agencies also designate “any habitat of such species which is then considered to be critical habitat.” The ESA also provides that each federal agency must ensure that any action they authorize, fund, or carry out is not likely to jeopardize the continued existence of a listed species or result in the destruction or adverse modification of its critical habitat. If an action is determined to result in adverse modification of critical habitat, the federal agency must adopt changes to the proposed action to avoid the adverse modification. These changes are often quite extensive and can affect the size, scope, and even the feasibility of a project moving forward. In February 2016, the U.S. Fish and Wildlife Service (USFWS) and the NMFS issued a set of regulatory and policy changes relating to critical habitat and adverse modification determinations under the ESA. While the ultimate impact of implementation of those changes is yet to be determined, taken as a whole, Idaho Power believes that the changes could result in the applicable agencies having greater authority in making designations of critical habitat and could increase the likelihood of adverse modification determinations.

The construction of generation, transmission, or distribution facilities and the relicensing of Idaho Power's hydroelectric projects can be federally authorized actions that fall under the ESA. There are a number of threatened or endangered species within Idaho Power's service area and within or near proposed transmission line routes, including the slickspot peppergrass. Further, there are a number of ESA-listed fish and other aquatic species located in waterways in which Idaho Power has hydroelectric facilities, including fall Chinook salmon, bull trout, Bliss Rapids snail, and Snake River physa snail. To date, efforts to protect these and other listed species have not significantly affected generation levels or operating costs at any of Idaho Power's hydroelectric facilities. However, the ongoing relicensing of the HCC presents endangered species and fisheries issues that may require operational adjustments and could adversely impact the amount of output from hydroelectric dams, potentially causing Idaho Power to rely on more expensive sources for power generation or market purchases.

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Developments in Regulation of Sage Grouse Habitat: In February 2016, a lawsuit was filed in the U.S. District Court of Idaho challenging the BLM's sage grouse resource management and land use plan revisions that became effective in 2015 under the Federal Land Policy and Management Act. The lawsuit challenges the plans and associated environmental impact statements across the sage grouse range and alleges that the plans fail to ensure that sage grouse populations and habitats will be protected and restored in accordance with the best available science and legal mandates. Further, the complaint challenges certain exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. Idaho Power has intervened in the proceedings in an effort to support the exemptions provided for in the BLM's plans.

In May 2016, a separate lawsuit was filed in the U.S. District Court of North Dakota, challenging the BLM's sage grouse resource management and land use plan revisions, including the exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. In October 2016, the plaintiffs amended their complaint to no longer challenge the exemptions; however, in December 2016, the North Dakota court transfered claims challenging certain Idaho land use plan amendments to the U.S. District Court for the District of Columbia. As of the date of this report, Idaho Power is participating in the proceedings in an effort to protect its interests.

ESA Issues Related to Specific Projects:

Hells Canyon Relicensing Project : In 2007, the FERC requested initiation of formal consultation under the ESA with the NMFS and the USFWS regarding potential effects of HCC relicensing on several listed aquatic and terrestrial species. Formal consultation has yet to be initiated and the NMFS and the USFWS continue to gather and consider information relative to the effects of relicensing on relevant ESA listed species. Idaho Power continues to cooperate with the USFWS, the NMFS, and the FERC in an effort to address ESA concerns. In December 2004, Idaho Power and eleven other parties, including NMFS and the USFWS, entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on ESA listed species pending the relicensing of the project. At the conclusion of formal consultation and with the issuance of biological opinions by the NMFS and the USFWS and an operating license by the FERC, Idaho Power may be required to implement additional measures or further modify or adjust operations to comply with Section 7 of the ESA. The issuance of a final biological opinion during 2017 is unlikely.

Boardman-to-Hemingway and Gateway West Transmission Projects : In August 2016, the USFWS re-instated the threatened species status of slickspot peppergrass. Most of the species are located on federal land. Idaho Power expects the listing of the slickspot peppergrass and its existence within or near the proposed routes for the Boardman-to-Hemingway and Gateway West transmission line projects to continue to impact the cost and timing of permitting and construction of the projects, as it requires an ESA Section 7 consultation. The USFWS has also indicated it intends to designate critical habitat for the species. If critical habitat is designated within the vicinity of the transmission line projects, Idaho Power expects that the designation could increase the cost of obtaining permits for the projects and could further delay the in-service date of the projects.

Endangered Species Act and National Environmental Policy Act Developments: In May 2016, the United States District Court for the District of Oregon issued an opinion finding that in the context of hydroelectric facilities owned and operated by the U.S. Army Corps of Engineers and located on the lower Snake River, National Oceanic and Atmospheric Administration's National Marine Fisheries Service (NOAA Fisheries) violated the ESA by using improper standards, failing to consider adequately the impact of climate change on habitat conditions, and placing undue reliance on unproven, future federal habitat conservation measures, particularly to the degree that the success of the measures could be undermined by climate change. The court also found that other federal agencies violated the National Environmental Policy Act (NEPA) by failing to prepare a comprehensive environmental impact statement on implementation of the conservation measures ordered by NOAA Fisheries, including analysis of the measures directed by NOAA Fisheries and other reasonable alternatives. The court’s opinion and its emphasis on a climate change-driven analysis element, if generalized to other situations, could require ESA-driven avoidance, minimization, and compensatory mitigation efforts to incorporate surplus measures to ensure species’ protection, which could result in considerable increases in cost beyond the cost of additional analysis in the NEPA process. In September 2016, federal agencies initiated an environmental impact statement process to examine hydroelectric dams on the lower Snake River, which Idaho Power expects will take place over a five-year period. None of Idaho Power’s hydroelectric facilities are included in the studies.

Climate Change and the Regulation of Greenhouse Gas Emissions

Overview: Long-term climate change could significantly affect Idaho Power's business in a variety of ways, including:


•	changes in temperature and precipitation could affect customer demand and energy loads;

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•	extreme weather events could increase service interruptions, outages, maintenance costs, and the need for additional backup systems, and can affect the supply of, and demand for, electricity and natural gas, which may impact the price of those and other commodities;


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


•	legislative and/or regulatory developments related to climate change could affect plants and operations, including restrictions on the construction of new generation resources, the expansion of existing resources, or the operation of generation resources; and


•	consumer preference for, and resource planning decisions requiring, renewable or low GHG-emitting sources of energy could impact usage of existing generation sources and require significant investment in new generation and transmission infrastructure.

Federal and state regulations pertaining to GHG emissions under the CAA have raised uncertainty about the future viability of fossil fuels, most notably coal, as an economical energy source for new and existing electric generation facilities because many new technologies for reducing CO ₂ emissions from coal, including carbon capture and storage, are still in the development stage and are not yet proven. Stringent emissions standards could result in significant increases in capital expenditures and operating costs, which may accelerate the retirement of coal-fired units and create power system reliability issues. Some higher-cost, high-emission coal-fired plants have ceased operation or the plant owners have announced a near-term cessation of operation, as the cost of compliance makes the plants uneconomical to operate, particularly in light of continued low natural gas prices that decrease the cost to operate natural gas-fired power plants.

A variety of factors contribute to the financial, regulatory, and logistical uncertainties related to GHG reductions. These include the specific GHG emissions limits imposed, the timing of implementation of these limits, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and the timing and amount of cost recovery through rates. Accordingly, Idaho Power cannot predict the effect on its results of operations, financial position, or cash flows of any GHG emission or other climate change requirements that may be adopted, although the costs to implement and comply with any such requirements could be substantial. A more detailed discussion of legislative and regulatory developments related to climate change follows.

National GHG Initiatives; Final Rule Under CAA Section 111(d): The EPA has become increasingly active in the regulation of GHGs. The EPA's endangerment finding in 2009 that GHGs threaten public health and welfare resulted in the enactment of a series of EPA regulations to address GHG emissions.

In May 2010, the EPA issued the “Tailoring Rule,” which set thresholds for GHG emissions that define when permits are required for new and existing industrial facilities. The final rule “tailors” the requirements of these CAA permitting programs to limit which facilities will be required to obtain Prevention of Significant Deterioration (PSD) and Title V permits. The rules require the use of "best available control technology" for GHG emissions if a new major source or modification of an existing major source is projected to result in GHG emissions of at least 75,000 tons per year (CO ₂ equivalent). In addition, Title V permit renewals or modifications for existing major sources must include applicable requirements relating to GHGs. While the rules are complex, Idaho Power believes that its owned and co-owned fossil fuel-fired generation plants are, as of the date of this report, in compliance with the GHG Tailoring Rule.

In June 2014, the EPA released, under Section 111(d) of the CAA, a proposed rule for addressing GHG from existing fossil fuel-fired electric generating units (EGUs). The proposed rule was intended to achieve a 30 percent reduction in CO ₂ emissions from the power sector by 2030. On August 3, 2015, the EPA released the final rule under Section 111(d) of the CAA, referred to as the Clean Power Plan, which requires states to adopt plans to collectively reduce 2005 levels of power sector CO ₂ emissions by 32 percent by the year 2030. The final rule provides states until September 2018 to submit implementation plans, phasing in several compliance periods beginning in 2022 and achieving the final emissions goals by 2030.

On February 9, 2016, the U.S. Supreme Court issued an order staying the implementation of the rule pending the completion of certain legal challenges, which has an uncertain impact on the ultimate timeline for implementation of the rule. Idaho Power's owned and co-owned generation facilities are in the states of Idaho, Nevada, Oregon, and Wyoming. Despite the current stay on implementation, Idaho Power is working with state representatives, neighboring utilities, and others as it analyzes the rule and prepares for compliance. Because the rule is premised on state implementation plans, the terms of which Idaho Power does not control, and due to the potential changes in legislation, regulation, and government policy with respect to environmental matters as a result of the 2016 U.S. presidential and congressional elections, as of the date of this report Idaho Power is unable to determine the financial or operational impacts of the final rule.

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State GHG Initiatives and Idaho Power’s Voluntary GHG Reduction Initiative: In August 2007, the Oregon legislature enacted legislation setting goals of reducing GHG levels to 10 percent below 1990 levels by 2020 and at least 75 percent below 1990 levels by 2050. Oregon imposes GHG emission reporting requirements on facilities emitting 2,500 metric tons or more of CO ₂ equivalent annually. The Boardman coal-fired power plant located in Oregon, in which Idaho Power is a 10-percent owner, is subject to and in compliance with Oregon's GHG reporting requirements but is scheduled to cease coal-fired operations in 2020.

In Oregon, legislation referred to as the Oregon Clean Electricity and Coal Transition Plan was enacted in March 2016, and may require certain large Oregon utilities to remove coal-fired generation from their Oregon retail rates by 2030. Oregon utilities would be permitted to sell the output of coal-fired plants into the wholesale market or reallocate such plants to other states. To the extent Idaho Power is subject to the legislation, it plans to seek recovery, through the ratemaking process, of operating and capitalized costs related to its coal-fired generation assets and removal of any of those assets from Oregon rate base.

The State of Idaho has not passed legislation specifically regulating GHGs, but in May 2007, Idaho’s governor issued Executive Order 2007-05, which directed the Idaho Department of Environmental Quality to work with the state government to implement GHG reductions within each agency, complete a statewide emissions inventory, and provide recommendations to the governor, among other tasks. Wyoming and Nevada similarly have not enacted legislation to regulate GHG emissions and do not have a reporting requirement, but they are members of the Climate Registry, a national, voluntary GHG emission reporting system. The Climate Registry is a collaboration aimed at developing and managing a common GHG emission reporting system across states, provinces, and tribes to track GHG emissions nationally. All states for which Idaho Power has traditional fuel generating plants (i.e. Idaho, Oregon, Wyoming, and Nevada) are members of the Climate Registry. Idaho Power is engaged in voluntary GHG emissions intensity reduction efforts, which is discussed in Part I, Item 1 - “Business - Utility Operations - Environmental Regulation and Costs ."

Clean Air Act Matters

Overview: In addition to the CAA developments related to GHG emissions described above, several other regulatory programs developed under the CAA apply to Idaho Power. These include the final Mercury and Air Toxics Standards (MATS), National Ambient Air Quality Standards (NAAQS), New Source Review / Prevention of Significant Deterioration (NSR/PSD)

Rules, and the Regional Haze Rule.

MATS Implementation: The final MATS rule under the CAA, previously referred to as the Utility MACT Rule, was issued in February 2012. The final rule established emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The MATS rule provided that sources must be in compliance with emission limits by April 2015. Idaho Power and the plant co-owners have installed mercury continuous emission monitoring systems on all of the coal-fired units at the Jim Bridger, Boardman, and North Valmy coal-fired generating plants, along with control technology to reduce mercury, acid gases, and particulate matter emissions for purposes of compliance with the MATS rule. Idaho Power believes that as of the date of this report, the coal-fired plants are in compliance with the MATS rule. Legal challenges relating to the MATS rule, to which Idaho Power is not a party and pursuant to which the EPA is performing a court-mandated cost analysis for the rule, are pending.

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National Ambient Air Quality Standards: The CAA requires the EPA to set ambient air quality standards for six "criteria" pollutants considered harmful to public health and the environment. These six pollutants are carbon monoxide, lead, ozone, particulate matter, nitrogen dioxide, and sulfur dioxide. States are then required to develop emission reduction strategies through State Implementation Plans, or SIPs, based on attainment of these ambient air quality standards. Recent developments and pending actions related to certain of those items relevant to Idaho Power include the following:

•

NO _x : In 2010, the EPA adopted a new NAAQS for NO _x at a level of 100 parts per billion averaged over a 1-hour period. In connection with the new NAAQS, in February 2012 the EPA issued a final rule designating all of the counties in Idaho, Nevada, Oregon, and Wyoming where Idaho Power owns or has an interest in a natural gas or coal-fired power plant as “unclassifiable/attainment” for NO _x . The EPA indicated it would review the designations after 2015, when three years of air quality monitoring data are available, and may formally designate the counties as attainment or non-attainment for NO _x . A designation of non-attainment may increase the likelihood that Idaho Power would be required to install costly pollution control technology at one or more of its plants.

•

SO ₂ : In 2010, the EPA adopted a new NAAQS for SO ₂ at a level of 75 parts per billion averaged over a one-hour period. In 2011, the states of Idaho, Nevada, Oregon, and Wyoming sent letters to the EPA recommending that all counties in these states be classified as "unclassifiable" under the new one-hour SO ₂ NAAQS because of a lack of definitive monitoring and modeling data. In February 2013, the EPA issued letters to the states of Idaho and Oregon, finding that the most recent air quality data for those states showed no violations of the 2010 SO ₂ standard. As a result, the EPA is waiting to propose designation actions for those states, and is likely to proceed with designation actions once additional data is gathered. Idaho Power expects that designations for Nevada and Wyoming will also be addressed in a separate future action.

•

Ozone : In late 2014, the EPA issued a proposed rule that would update the ozone standard under the CAA, from 75 parts per billion over an eight-hour period to 65 to 70 parts per billion over an eight-hour period. On October 1, 2015, the EPA issued a final rule lowering the national ozone standard under the CAA to 70 parts per billion. The EPA stated that the vast majority of U.S. counties will meet the standards by 2025 with federal and state rules and programs now in place or underway. The EPA's plan provides for finalizing non-attainment designations in 2017, and it plans to propose rules and guidance over the next year to help states with potential non-attainment areas implement the revised standards. Non-attainment areas will have until 2020 to late 2037 to meet the new standard, with attainment dates varying based on the ozone level in the area. Due to high levels of background ozone, which can be caused by factors such as elevation, vegetation, wildfire, and international transport, attainment in areas within the Intermountain West may be difficult, and the formulation of state implementation plans to bring an area into compliance with the new standard may be challenging due to the existence of ozone caused by factors outside of local control. If the EPA were to make non-attainment determinations in areas where Idaho Power owns or co-owns power plants, or proposes to construct power plants, the state implementation plan for those areas could result in changes to the nature and frequency of operation of existing generation plants and make more difficult or costly the construction of new power generation plants. Idaho Power will seek to work with state regulators on implementation plans for any non-attainment areas, in an effort to reduce the potential adverse impact on Idaho Power's operation of its existing power generation plants and construction of future facilities.

Because the EPA has not yet completed the designation of areas as attaining or not attaining the NAAQS for NO _x , SO ₂ , and ozone, Idaho Power is unable to predict what impact the adoption and implementation of these standards may have on its operations, though it does expect at least some increases in capital and operating costs from the standards if areas in which Idaho Power operate, or adjacent areas, receive non-attainment designations.

Regional Haze Rules: In accordance with federal regional haze rules under the CAA, coal-fired utility boilers are subject to regional haze - best available retrofit technology (RH BART) if they were built between 1962 and 1977 and affect any "Class I" (wilderness) areas. This includes all four units at the Jim Bridger and the Boardman coal-fired plants. The RH BART rules would have required installation of a suite of emissions controls at the Boardman plant; however, in December 2010, the Oregon Environmental Quality Commission approved a plan to install a less costly suite of environmental controls and cease coal-fired operations at the Boardman power plant no later than December 31, 2020.

In December 2009, the Wyoming Department of Environmental Quality (WDEQ) issued a RH BART permit to PacifiCorp as the operator of the Jim Bridger plant. As part of the WDEQ's long term strategy for regional haze, the permit required that PacifiCorp install SCR equipment for NO _x control at Jim Bridger units 3 and 4 by December 31, 2015 and December 31, 2016, respectively, which has been completed, and submit an application by December 31, 2017 to install add-on NO _x controls at Jim Bridger unit 2 by 2021 and unit 1 by 2022. In November 2010, PacifiCorp and the WDEQ signed a settlement agreement under

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which PacifiCorp agreed to the timing and nature of the controls. The settlement agreement was conditioned on the EPA ultimately approving those portions of the Wyoming regional haze SIP that are consistent with the terms of the settlement agreement. In January 2014, the EPA approved Wyoming's regional haze SIP as to the Jim Bridger plant, with the NO _x control compliance dates set forth in the settlement agreement. Several interested parties have appealed the EPA's decisions on Wyoming's regional haze SIP on various grounds. Idaho Power has not appealed the EPA's decisions but has intervened in the proceedings to participate if and to the extent the Jim Bridger plant could be affected.

Clean Water Act Matters

Definition of “Waters of the United States” Under the CWA : On August 28, 2015, the EPA's and U.S. Army Corps of Engineers' final rule defining the phrase "waters of the United States" under the CWA became effective. Idaho Power believes that the final rule potentially expands federal jurisdiction under the CWA beyond traditional navigable waters, interstate waters, territorial seas, tributaries, and adjacent wetlands, to a number of other waters, including waters with a "significant nexus" to those traditional waters. As a result of the potential expansion, the final rule may result in additional permitting and regulatory requirements under multiple provisions of the CWA. Idaho Power has analyzed the final rule and expects that while it may incur additional permitting and other costs associated with the rule, the aggregate amount of increased costs is unlikely to have a material adverse effect on Idaho Power's operations or financial condition, in part due to the relatively arid climate of Idaho Power's service area and the existing application of the CWA to most of Idaho Power's facilities, including its hydroelectric plants.

In October 2015, the United States Court of Appeals for the Sixth Circuit issued a nationwide stay of the final waters of the United States rule from becoming effective. In response to the Sixth Circuit's decision, the EPA resumed nationwide use of the agency's prior regulations defining the term “waters of the United States.” The EPA stated that those regulations will be implemented as they were prior to August 27, 2015, by applying relevant case law, applicable policy, and the best science and technical data on a case-by-case basis in determining which waters are protected by the CWA.

CWA Matters Related to Hydroelectric Relicensing: Idaho Power is also addressing CWA issues associated with the relicensing of its HCC. See “Relicensing of Hydroelectric Projects” in this MD&A for additional information on the impact of the CWA on that relicensing effort.

Review of Federal Coal Leases

In January 2016, the U.S. Department of the Interior announced that it would launch a comprehensive review to identify and evaluate potential reforms to the federal coal lease program. The review is intended to address questions such as how, when, and where to lease coal resources, how to account for the environmental and public health impacts of federal coal production, and how to ensure taxpayers are earning a fair return for the use of the coal resources. The U.S. Department of the Interior stated that it will not issue new coal leases during the pendency of the review, except under limited circumstances, but mining under existing leases will not be suspended during the review. BCC, which mines and supplies coal to the Jim Bridger coal-fired power plant, currently leases its coal under federal, state, and private coal leases. It is uncertain how new federal lease applications will be handled during the U.S. Department of the Interior's coal lease review. Idaho Power believes that BCC has adequate reserves under existing leases to satisfy its coal delivery obligations to the Jim Bridger plant during the term of the existing coal supply contract through 2024, and that the Jim Bridger plant will otherwise have access to sufficient coal supplies for its operation for the foreseeable future. However, depending on the outcome of the Department of the Interior's review, the availability of coal resources could decline and the cost of leases for coal resources could increase, which could increase the fuel cost for each of Idaho Power's co-owned coal-fired plants.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

When preparing financial statements in accordance with GAAP, IDACORP’s and Idaho Power’s management must apply accounting policies and make estimates that affect the reported amounts of assets, liabilities, revenues, and expenses and related disclosure of contingent assets and liabilities. These estimates often involve judgment about factors that are difficult to predict and are beyond management’s control. Management adjusts these estimates based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances. Actual amounts could materially differ from the estimates. Management believes the accounting policies and estimates discussed below are the most critical to the portrayal of their financial condition and results of operations and require management’s most difficult, subjective, or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain and may change in subsequent periods.

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Accounting for Rate Regulation

Entities that meet specific conditions are required by GAAP to reflect the impact of regulatory decisions in their consolidated financial statements and to defer certain costs as regulatory assets until matching revenues can be recognized. Similarly, certain items may be deferred as regulatory liabilities. Idaho Power must satisfy three conditions to apply regulatory accounting: (1) an independent regulator must set rates; (2) the regulator must set the rates to cover specific costs of delivering service; and (3) the service territory must lack competitive pressures to reduce rates below the rates set by the regulator.

Idaho Power has determined that it meets these conditions, and its financial statements reflect the effects of the different rate-making principles followed by the jurisdictions regulating Idaho Power. The primary effect of this policy is that Idaho Power had recorded $1.5 billion of regulatory assets and $447 million of regulatory liabilities at December 31, 2016 . Idaho Power expects to recover these regulatory assets from customers through rates and refund these regulatory liabilities to customers through rates, but recovery or refund is subject to final review by the regulatory bodies. If future recovery or refund of these amounts ceases to be probable, or if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate those regulatory assets or liabilities. Either circumstance could have a material effect on Idaho Power’s financial condition or results of operations.

Income Taxes

IDACORP and Idaho Power use judgment and estimation in developing the provision for income taxes and the reporting of tax-related assets and liabilities. The interpretation of tax laws can involve uncertainty, since tax authorities may interpret such laws differently. Actual income taxes could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities.

Idaho Power provides deferred income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial statement purposes. Deferred income taxes for other items are provided for the temporary differences between the income tax and financial accounting treatment of such items. Unless contrary to applicable income tax guidance, deferred income taxes are not provided for those income tax temporary differences where the prescribed regulatory accounting methods, or flow-through, direct Idaho Power to recognize the tax impacts currently for rate making and financial reporting.

Refer to Note 1 - “Summary of Significant Accounting Policies” and Note 2 - “Income Taxes” to the consolidated financial statements included in this report for additional information relating to income taxes.

Pension and Other Postretirement Benefits

Idaho Power maintains a tax-qualified, noncontributory defined benefit pension plan covering most employees, an unfunded nonqualified deferred compensation plan for certain senior management employees and directors called the Security Plan for Senior Management Employees (SMSP), and a postretirement benefit plan (consisting of health care and death benefits).

The costs IDACORP and Idaho Power record for these plans depend on the provisions of the plans, changing employee demographics, actual returns on plan assets, and several assumptions used in the actuarial valuations from which the expense is derived. The key actuarial assumptions that affect expense are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Management evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future stock market performance, changes in interest rates, and other factors used to develop the actuarial assumptions are uncertain, and actual results could vary significantly from the estimates.

The assumed discount rate is based on reviews of market yields on high-quality corporate debt. Specifically, IDACORP and Idaho Power determined the discount rate for each plan through the construction of hypothetical portfolios of bonds selected from high-quality corporate bonds available as of December 31, 2016 , with maturities matching the projected cash outflows of the plans. Based on the results of this analysis, the discount rate used to calculate the 2017 pension expense will be decreased to 4.45 percent from the 4.60 percent used in 2016 .

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Power believes the result provides a reasonable prediction of future investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over the past 20 years when interest rates were generally much higher. The long-term rate of return used to calculate the 2017 pension expense will be 7.5 percent, the same assumption as was used for 2016 .

Gross net periodic pension and other postretirement benefit cost for these plans totaled $52 million , $51 million , and $32 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For 2017 , gross pension and other postretirement benefit costs are expected to total approximately $51 million , which takes into account the change in the discount rate noted above.

Had different actuarial assumptions been used, pension expense could have varied significantly. The following table reflects the sensitivities associated with changes in the discount rate and rate-of-return on plan assets actuarial assumptions on historical and future pension and postretirement expense:



	Discount rate						Rate of return
	2017			2016			2017			2016
	(millions of dollars)
Effect of 0.5% rate increase on net periodic benefit cost	$	(7.2	)	$	(6.9	)	$	(3.2	)	$	(2.9	)
Effect of 0.5% rate decrease on net periodic benefit cost	7.9			7.6			3.2			2.9

Additionally, a 0.5 percent increase in the plans' discount rates would have resulted in a $74 million decrease in the combined benefit obligations of the plans as of December 31, 2016 . A 0.5 percent decrease in the plans' discount rates would have resulted in an $83 million increase in the combined benefit obligations of the plans as of December 31, 2016 .

The IPUC has authorized Idaho Power to account for its defined benefit pension plan expense on a cash basis, and to defer and account for accrued pension expense as a regulatory asset. The IPUC acknowledged that it is appropriate for Idaho Power to seek recovery in its revenue requirement of reasonable and prudently incurred pension expense based on actual cash contributions. In 2007, Idaho Power began deferring pension expense to a regulatory asset account to be matched with revenue when future pension contributions are recovered through rates. At December 31, 2016 , a total of $105 million of expense was deferred as a regulatory asset. Approximately $23 million is expected to be deferred in 2017 . Idaho Power recorded pension expense in 2016 , 2015 , and 2014 of $19 million , $19 million , and $35 million , respectively.

Refer to Note 11 – “Benefit Plans” to the consolidated financial statements included in this report for additional information relating to pension and postretirement benefit plans.

Contingent Liabilities

An estimated loss from a loss contingency is charged to income if (a) it is probable that a liability had been incurred at the date of the financial statements and (b) the amount of the loss can be reasonably estimated. If a probable loss cannot be reasonably estimated, no accrual is recorded but disclosure of the contingency, if material, in the notes to the financial statements is required. Gain contingencies are not recorded until realized. IDACORP and Idaho Power have a number of unresolved issues related to regulatory and legal matters. If the recognition criteria have been met, liabilities have been recorded. Estimates of this nature are highly subjective and the final outcome of these matters could vary significantly from the amounts that have been included in the financial statements.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

For a listing of new and recently adopted accounting standards, see Note 1 - "Summary of Significant Accounting Policies" to the notes to the consolidated financial statements included in this report.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and Idaho Power are exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk, and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments, and derivative commodity instruments sensitive to changes in interest rates, commodity prices, and equity prices that were held at December 31, 2016 . IDACORP and Idaho Power have not entered into any of these market-risk-sensitive instruments for trading purposes.

Interest Rate Risk

IDACORP and Idaho Power manage interest expense and short- and long-term liquidity through a combination of fixed rate and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly-rated financial institutions may be used to achieve the desired combination.

Variable Rate Debt : As of December 31, 2016 , IDACORP and Idaho Power had $1.1 million and $16.1 million in floating rate debt, net of short-term investments. The fair market value of this debt approximates the net carrying amount as the cost of borrowing is variable and approximates current market rates. Assuming no change in financial structure, if variable interest rates were to average one percentage point higher than the average rate on December 31, 2016 , annual interest expense would increase and pre-tax earnings would decrease by an insignificant amount for both IDACORP and Idaho Power.

Fixed Rate Debt : As of December 31, 2016 , both IDACORP and Idaho Power had $1.7 billion in fixed rate debt, with a fair market value of approximately $1.8 billion. These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $256 million if market interest rates were to decline by one percentage point from their December 31, 2016 , levels.

Commodity Price Risk

IDACORP's exposure to changes in commodity prices is related to Idaho Power's ongoing utility operations that produce electricity to meet the demand of its retail electric customers. These effects of changes in commodity prices on Idaho Power are mitigated in large part by Idaho Power's Idaho and Oregon power cost adjustment mechanisms. To supplement its generation resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. These purchased power arrangements allow Idaho Power to respond to fluctuations in the demand for electricity and variability in generating plant operations. Idaho Power also enters into arrangements for the purchase of fuel for natural gas and coal-fired generating plants. These contracts for the purchase of power and fuel expose Idaho Power to commodity price risk.

A number of factors associated with the structure and operation of the energy markets influence the level and volatility of prices for energy commodities and related derivative products. The weather is a major uncontrollable factor affecting the local and regional demand for electricity and the availability and cost of power generation. Other factors include the occurrence and timing of demand peaks due to seasonal, daily, and hourly power demand; power supply; power transmission capacity; changes in federal and state regulation and compliance obligations; fuel supplies; and market liquidity.

The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, to maintain appropriate physical reserves to ensure reliability, and to make economic use of temporary surpluses that may develop. Idaho Power has adopted a risk management program, which has been reviewed and accepted by the IPUC, designed to reduce exposure to power supply cost-related uncertainty, further mitigating commodity price risk. Idaho Power’s Energy Risk Management Policy (Policy) and associated standards implementing the Policy describe a collaborative process with customers and regulators via a committee called the Customer Advisory Group (CAG). The Risk Management Committee (RMC), comprised of selected Idaho Power officers and other senior staff, oversees the risk management program. The RMC is responsible for communicating the status of risk management activities to the Idaho Power Board of Directors and to the CAG, and Idaho Power’s Audit Committee is responsible for approving the Policy and associated standards. The RMC is also responsible for conducting an ongoing general assessment of the appropriateness of Idaho Power’s strategies for energy risk management activities. In its risk management process, Idaho Power considers both demand-side and supply-side options consistent with its IRP. The primary tools for risk mitigation are physical and financial forward power transactions and fueling alternatives for utility-owned generation resources. Idaho Power only engages in a nominal amount of trading activity for non-retail purposes.

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The Policy requires monitoring monthly volumetric electricity position and total monthly dollar (net power supply cost) exposure on a rolling 18-month forward view. The power supply business unit produces and evaluates projections of the operating plan based on factors such as forecasted resource availability, stream flows, and load, and orders risk mitigating actions, including resource optimization and hedging strategies, dictated by the limits stated in the Policy to bring exposures within pre-established risk guidelines. The RMC evaluates the actions initiated by power supply for consistency and compliance with the Policy. Idaho Power representatives meet with the CAG at least annually to assess effectiveness of the limits. Changes to the limits can be endorsed by the CAG and referred to the board of directors for approval.

Credit Risk

IDACORP is subject to credit risk based on Idaho Power's activity with market counterparties. Idaho Power is exposed to this risk to the extent that a counterparty may fail to fulfill a contractual obligation to provide energy, purchase energy, or complete financial settlement for market activities. Idaho Power mitigates this exposure by actively establishing credit limits; measuring, monitoring, and reporting credit risk using appropriate contractual arrangements; and transferring of credit risk through the use of financial guarantees, cash, or letters of credit. Idaho Power maintains a current list of acceptable counterparties and credit limits.

The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of December 31, 2016 , Idaho Power had no performance assurance collateral posted. Should Idaho Power experience a reduction in its credit rating on Idaho Power’s unsecured debt to below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s energy and fuel portfolio and market conditions as of December 31, 2016 , the amount of collateral that could be requested upon a downgrade to below investment grade was approximately $11.6 million. To minimize capital requirements, Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls through sensitivity analysis.

Idaho Power is obligated to provide service to all electric customers within its service area. Credit risk for Idaho Power’s retail customers is managed by credit and collection policies that are governed by rules issued by the IPUC or OPUC. Idaho Power records a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. Idaho Power continuously monitors levels of nonpayment from customers and makes any necessary adjustments to its provision for uncollectible accounts accordingly.

Idaho utility customer relations rules prohibit Idaho Power from terminating electric service during the months of December through February to any residential customer who declares that he or she is unable to pay in full for utility service and whose household includes children, elderly, or infirm persons. Idaho Power’s provision for uncollectible accounts could be affected by changes in future prices as well as changes in IPUC or OPUC regulations.

Equity Price Risk

IDACORP is exposed to price fluctuations in equity markets, primarily through Idaho Power's defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity security investments at Idaho Power. The equity securities held by the pension plan and in such accounts are diversified to achieve broad market participation and reduce the impact of any single investment, sector, or geographic region. Idaho Power has established asset allocation targets for the pension plan holdings, which are described in Note 11 - "Benefit Plans" to the consolidated financial statements included in this report.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements and Financial Statement Schedules



Consolidated Financial Statements	Page

IDACORP, Inc.:
Consolidated Statements of Income	74
Consolidated Statements of Comprehensive Income	75
Consolidated Balance Sheets	76
Consolidated Statements of Cash Flows	78
Consolidated Statements of Equity	79

Idaho Power Company:
Consolidated Statements of Income	80
Consolidated Statements of Comprehensive Income	81
Consolidated Balance Sheets	82
Consolidated Statements of Cash Flows	84
Consolidated Statements of Retained Earnings	85

Notes to the Consolidated Financial Statements	86
Reports of Independent Registered Public Accounting Firm	125

Supplemental Financial Information and Financial Statement Schedules

Supplemental Financial Information (unaudited)	127
Financial Statement Schedules
IDACORP, Inc. - Schedule I - Condensed Financial Information of Registrant	141
IDACORP, Inc. - Schedule II - Consolidated Valuation and Qualifying Accounts	143
Idaho Power Company - Schedule II - Consolidated Valuation and Qualifying Accounts	144

All other schedules have been omitted because they are not required, not applicable, or the required information is otherwise included.

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IDACORP, Inc.

Consolidated Statements of Income



	Year Ended December 31,
	2016			2015			2014
	(thousands of dollars except for per share amounts)
Operating Revenues:
Electric utility:
General business	$	1,145,993		$	1,151,038		$	1,122,281
Off-system sales	25,205			30,887			77,165
Other revenues	88,155			85,580			79,205
Total electric utility revenues	1,259,353			1,267,505			1,278,651
Other	2,667			2,784			3,873
Total operating revenues	1,262,020			1,270,289			1,282,524

Operating Expenses:
Electric utility:
Purchased power	245,764			226,470			244,628
Fuel expense	179,491			186,231			201,241
Power cost adjustment	(5,330		)	16,766			22,235
Other operations and maintenance	351,893			342,146			354,567
Energy efficiency programs	33,754			30,532			27,154
Depreciation	143,661			138,110			132,987
Taxes other than income taxes	32,823			32,808			31,748
Total electric utility expenses	982,056			973,063			1,014,560
Other	8,188			15,129			14,268
Total operating expenses	990,244			988,192			1,028,828
Operating Income	271,776			282,097			253,696
Allowance for Equity Funds Used During Construction	22,031			21,785			17,931
Earnings of Unconsolidated Equity-Method Investments	12,871			11,128			12,372
Other Income, Net	9,874			7,159			6,328
Interest Expense:
Interest on long-term debt	81,956			83,056			80,562
Other interest	10,273			8,922			7,703
Allowance for borrowed funds used during construction	(10,194		)	(10,044		)	(8,464		)
Total interest expense, net	82,035			81,934			79,801
Income Before Income Taxes	234,517			240,235			210,526
Income Tax Expense	36,429			45,760			16,772
Net Income	198,088			194,475			193,754
Adjustment for loss (income) attributable to noncontrolling interests	200			204			(274		)
Net Income Attributable to IDACORP, Inc.	$	198,288		$	194,679		$	193,480
Weighted Average Common Shares Outstanding - Basic (000’s)	50,298			50,220			50,131
Weighted Average Common Shares Outstanding - Diluted (000’s)	50,373			50,292			50,199
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$	3.94		$	3.88		$	3.86
Earnings Attributable to IDACORP, Inc. - Diluted	$	3.94		$	3.87		$	3.85

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Consolidated Statements of Comprehensive Income



	Year Ended December 31,
	2016		2015		2014
	(thousands of dollars)

Net Income	$	198,088	$	194,475	$	193,754
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax of $253, $1,851, and $(4,881)	394		2,882		(7,605		)
Total Comprehensive Income	198,482		197,357		186,149
Comprehensive loss (income) attributable to noncontrolling interests	200		204		(274		)
Comprehensive Income Attributable to IDACORP, Inc.	$	198,682	$	197,561	$	185,875

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Consolidated Balance Sheets



	December 31,
	2016			2015
	(thousands of dollars)
Assets

Current Assets:
Cash and cash equivalents	$	61,480		$	114,802
Receivables:
Customer (net of allowance of $968 and $1,196, respectively)	71,557			73,505
Other (net of allowance of $164 and $159, respectively)	15,280			8,642
Income taxes receivable	12,781			13,058
Accrued unbilled revenues	80,738			65,805
Materials and supplies (at average cost)	57,858			56,924
Fuel stock (at average cost)	53,698			61,818
Prepayments	18,389			17,979
Current regulatory assets	62,570			49,215
Other	5,961			288
Total current assets	440,312			462,036

Investments	125,164			140,743

Property, Plant and Equipment:
Utility plant in service	5,732,044			5,485,464
Accumulated provision for depreciation	(1,988,477		)	(1,913,927		)
Utility plant in service - net	3,743,567			3,571,537
Construction work in progress	405,069			396,931
Utility plant held for future use	7,441			7,090
Other property, net of accumulated depreciation	15,922			16,855
Property, plant and equipment - net	4,171,999			3,992,413

Other Assets:
American Falls and Milner water rights	9,487			11,592
Company-owned life insurance	57,553			48,566
Regulatory assets	1,409,329			1,305,210
Long-term receivables (net of allowance of $402 and $552, respectively)	23,482			22,538
Other	52,571			40,216
Total other assets	1,552,422			1,428,122

Total	$	6,289,897		$	6,023,314

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Consolidated Balance Sheets



	December 31,
	2016			2015
	(thousands of dollars)
Liabilities and Equity

Current Liabilities:
Current maturities of long-term debt	$	1,064		$	1,064
Notes payable	21,800			20,000
Accounts payable	106,194			95,526
Taxes accrued	11,348			10,762
Interest accrued	22,377			22,292
Accrued compensation	45,787			42,961
Current regulatory liabilities	9,944			2,217
Advances from customers	21,438			31,214
Other	9,763			16,270
Total current liabilities	249,715			242,306

Other Liabilities:
Deferred income taxes	1,244,250			1,137,375
Regulatory liabilities	436,845			416,282
Pension and other postretirement benefits	411,523			394,030
Other	45,084			45,867
Total other liabilities	2,137,702			1,993,554

Long-Term Debt	1,744,614			1,725,410

Commitments and Contingencies

Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (shares authorized 120,000,000; 50,420,017 and 50,352,051 shares issued, respectively)	851,833			849,112
Retained earnings	1,323,198			1,230,105
Accumulated other comprehensive loss	(20,882		)	(21,276		)
Treasury stock (23,244 and 11,221 shares at cost, respectively)	(243		)	(57		)
Total IDACORP, Inc. shareholders’ equity	2,153,906			2,057,884
Noncontrolling interests	3,960			4,160
Total equity	2,157,866			2,062,044

Total	$	6,289,897		$	6,023,314

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Consolidated Statements of Cash Flows



	Year Ended December 31,
	2016			2015			2014
	(thousands of dollars)
Operating Activities:
Net income	$	198,088		$	194,475		$	193,754
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	147,294			142,581			137,088
Deferred income taxes and investment tax credits	35,732			38,645			19,163
Changes in regulatory assets and liabilities	(5,650		)	13,699			32,135
Pension and postretirement benefit plan expense	29,581			30,207			44,627
Contributions to pension and postretirement benefit plans	(45,301		)	(42,843		)	(33,720		)
Earnings of unconsolidated equity-method investments	(12,871		)	(11,128		)	(12,372		)
Distributions from unconsolidated equity-method investments	25,641			12,458			5,261
Allowance for equity funds used during construction	(22,031		)	(21,785		)	(17,931		)
Gain on sale of investments and assets	(103		)	(97		)	(193		)
Other non-cash adjustments to net income, net	5,108			2,788			5,085
Change in:
Accounts receivable	(2,671		)	4,740			20,433
Accounts payable and other accrued liabilities	13,300			2,440			6,359
Taxes accrued/receivable	662			818			(13,631		)
Other current assets	(10,887		)	(14,861		)	(13,124		)
Other current liabilities	(3,283		)	403			1,771
Other assets	(3,897		)	3,021			(3,655		)
Other liabilities	(1,006		)	(2,367		)	(6,707		)
Net cash provided by operating activities	347,706			353,194			364,343
Investing Activities:
Additions to property, plant and equipment	(296,950		)	(294,021		)	(274,094		)
Payments received from transmission project joint funding partners	7,586			11,377			—
Purchase of available-for-sale securities	(14,917		)	(14,106		)	(8,000		)
Proceeds from sale of available-for-sale securities	15,693			34,243			—
Purchase of life insurance investment	(10,000		)	(30,000		)	—
Other	1,144			801			9,674
Net cash used in investing activities	(297,444		)	(291,706		)	(272,420		)
Financing Activities:
Issuance of long-term debt	120,000			250,000			—
Retirement of long-term debt	(101,064		)	(121,064		)	(1,064		)
Dividends on common stock	(104,984		)	(96,810		)	(88,489		)
Net change in short-term borrowings	1,800			(11,300		)	(23,450		)
Acquisition of treasury stock	(3,329		)	(3,277		)	(2,737		)
Make-whole premium on retirement of long-term debt	(13,895		)	(17,872		)	—
Other	(2,112		)	(3,171		)	2,463
Net cash used in financing activities	(103,584		)	(3,494		)	(113,277		)
Net (decrease) increase in cash and cash equivalents	(53,322		)	57,994			(21,354		)
Cash and cash equivalents at beginning of the year	114,802			56,808			78,162
Cash and cash equivalents at end of the year	$	61,480		$	114,802		$	56,808
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Income taxes	$	3,302		$	8,857		$	11,364
Interest (net of amount capitalized)	$	78,334		$	79,442		$	77,295
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	34,603		$	23,840		$	28,438

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Consolidated Statements of Equity



	Year Ended December 31,
	2016			2015			2014
	(thousands of dollars)
Common Stock:
Balance at beginning of year	$	849,112		$	845,402		$	839,750
Cumulative effect of change in accounting principle	234			—			—
Issued	—			—			195
Other	2,487			3,710			5,457
Balance at end of year	851,833			849,112			845,402

Retained Earnings:
Balance at beginning of year	1,230,105			1,132,237			1,027,461
Cumulative effect of change in accounting principle	(234		)	—			—
Net income attributable to IDACORP, Inc.	198,288			194,679			193,480
Common stock dividends ($2.08, $1.92, and $1.76 per share, respectively)	(104,961		)	(96,811		)	(88,704		)
Balance at end of year	1,323,198			1,230,105			1,132,237

Accumulated Other Comprehensive (Loss) Income:
Balance at beginning of year	(21,276		)	(24,158		)	(16,553		)
Unfunded pension liability adjustment (net of tax)	394			2,882			(7,605		)
Balance at end of year	(20,882		)	(21,276		)	(24,158		)

Treasury Stock:
Balance at beginning of year	(57		)	(280		)	(8		)
Issued	3,143			3,500			2,465
Acquired	(3,329		)	(3,277		)	(2,737		)
Balance at end of year	(243		)	(57		)	(280		)

Total IDACORP, Inc. shareholders’ equity at end of year	2,153,906			2,057,884			1,953,201

Noncontrolling Interests:
Balance at beginning of year	4,160			4,364			4,090
Net (loss) income attributable to noncontrolling interests	(200		)	(204		)	274
Balance at end of year	3,960			4,160			4,364

Total equity at end of year	$	2,157,866		$	2,062,044		$	1,957,565

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Consolidated Statements of Income



	Year Ended December 31,
	2016			2015			2014
	(thousands of dollars)
Operating Revenues:
General business	$	1,145,993		$	1,151,038		$	1,122,281
Off-system sales	25,205			30,887			77,165
Other revenues	88,155			85,580			79,205
Total operating revenues	1,259,353			1,267,505			1,278,651

Operating Expenses:
Operation:
Purchased power	245,764			226,470			244,628
Fuel expense	179,491			186,231			201,241
Power cost adjustment	(5,330		)	16,766			22,235
Other operations and maintenance	351,893			342,146			354,567
Energy efficiency programs	33,754			30,532			27,154
Depreciation	143,661			138,110			132,987
Taxes other than income taxes	32,823			32,808			31,748
Total operating expenses	982,056			973,063			1,014,560

Income from Operations	277,297			294,442			264,091

Other Income (Expense):
Allowance for equity funds used during construction	22,031			21,785			17,931
Earnings of unconsolidated equity-method investments	10,855			9,773			10,814
Other expense, net	(1,944		)	(5,071		)	(4,363		)
Total other income	30,942			26,487			24,382

Interest Charges:
Interest on long-term debt	81,956			83,056			80,562
Other interest	10,050			8,706			7,472
Allowance for borrowed funds used during construction	(10,194		)	(10,044		)	(8,464		)
Total interest charges	81,812			81,718			79,570

Income Before Income Taxes	226,427			239,211			208,903

Income Tax Expense	37,185			48,228			19,516

Net Income	$	189,242		$	190,983		$	189,387

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Consolidated Statements of Comprehensive Income



	Year Ended December 31,
	2016		2015		2014
	(thousands of dollars)

Net Income	$	189,242	$	190,983	$	189,387
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax of $253, $1,851, and $(4,881)	394		2,882		(7,605		)
Total Comprehensive Income	$	189,636	$	193,865	$	181,782

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Consolidated Balance Sheets



	December 31,
	2016			2015
	(thousands of dollars)
Assets

Electric Plant:
In service (at original cost)	$	5,732,044		$	5,485,464
Accumulated provision for depreciation	(1,988,477		)	(1,913,927		)
In service - net	3,743,567			3,571,537
Construction work in progress	405,069			396,931
Held for future use	7,441			7,090
Electric plant - net	4,156,077			3,975,558

Investments and Other Property	107,379			121,267

Current Assets:
Cash and cash equivalents	44,140			110,756
Receivables:
Customer (net of allowance of $968 and $1,196, respectively)	71,557			73,505
Other (net of allowance of $164 and $159, respectively)	7,555			8,520
Income taxes receivable	23,334			5,432
Accrued unbilled revenues	80,738			65,805
Materials and supplies (at average cost)	57,858			56,924
Fuel stock (at average cost)	53,698			61,818
Prepayments	18,270			17,846
Current regulatory assets	62,570			49,215
Other	5,962			288
Total current assets	425,682			450,109

Deferred Debits:
American Falls and Milner water rights	9,487			11,592
Company-owned life insurance	57,553			48,566
Regulatory assets	1,409,329			1,305,210
Other	71,237			56,533
Total deferred debits	1,547,606			1,421,901

Total	$	6,236,744		$	5,968,835

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Consolidated Balance Sheets



	December 31,
	2016			2015
	(thousands of dollars)
Capitalization and Liabilities

Capitalization:
Common stock equity:
Common stock, $2.50 par value (50,000,000 shares authorized; 39,150,812 shares outstanding)	$	97,877		$	97,877
Premium on capital stock	712,258			712,258
Capital stock expense	(2,097		)	(2,097		)
Retained earnings	1,211,547			1,127,426
Accumulated other comprehensive loss	(20,882		)	(21,276		)
Total common stock equity	1,998,703			1,914,188
Long-term debt	1,744,614			1,725,410
Total capitalization	3,743,317			3,639,598

Current Liabilities:
Current maturities of long-term debt	1,064			1,064
Notes payable	21,800			—
Accounts payable	105,846			94,970
Accounts payable to related parties	1,056			1,059
Taxes accrued	11,348			10,745
Interest accrued	22,377			22,292
Accrued compensation	45,622			42,835
Current regulatory liabilities	9,944			2,217
Advances from customers	21,438			31,214
Other	9,103			15,506
Total current liabilities	249,598			221,902

Deferred Credits:
Deferred income taxes	1,351,415			1,252,371
Regulatory liabilities	436,845			416,282
Pension and other postretirement benefits	411,523			394,030
Other	44,046			44,652
Total deferred credits	2,243,829			2,107,335

Commitments and Contingencies

Total	$	6,236,744		$	5,968,835

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Consolidated Statements of Cash Flows



	Year Ended December 31,
	2016			2015			2014
	(thousands of dollars)
Operating Activities:
Net income	$	189,242		$	190,983		$	189,387
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	146,694			141,972			136,496
Deferred income taxes and investment tax credits	25,780			25,702			15,454
Changes in regulatory assets and liabilities	(5,651		)	13,699			32,135
Pension and postretirement benefit plan expense	29,597			30,185			44,579
Contributions to pension and postretirement benefit plans	(45,317		)	(42,821		)	(33,672		)
Earnings of unconsolidated equity-method investments	(10,855		)	(9,773		)	(10,814		)
Distributions from unconsolidated equity-method investments	23,716			10,833			3,586
Allowance for equity funds used during construction	(22,031		)	(21,785		)	(17,931		)
Gain on sale of investments and assets	(103		)	(97		)	(186		)
Other non-cash adjustments to net income, net	(454		)	(687		)	2,087
Change in:
Accounts receivable	3,590			1,998			20,072
Accounts payable	13,308			2,646			6,183
Taxes accrued/receivable	(17,299		)	17,179			(22,911		)
Other current assets	(10,902		)	(14,849		)	(13,137		)
Other current liabilities	(3,322		)	443			1,776
Other assets	(3,897		)	3,021			(3,655		)
Other liabilities	(829		)	(2,222		)	(6,238		)
Net cash provided by operating activities	311,267			346,427			343,211
Investing Activities:
Additions to utility plant	(296,948		)	(293,968		)	(273,911		)
Payments received from transmission project joint funding partners	7,586			11,377			—
Purchase of available-for-sale securities	(14,917		)	(14,106		)	(8,000		)
Proceeds from the sale of available-for-sale securities	15,693			34,243			—
Purchase of life insurance investment	(10,000		)	(30,000		)	—
Other	1,000			706			8,508
Net cash used in investing activities	(297,586		)	(291,748		)	(273,403		)
Financing Activities:
Issuance of long-term debt	120,000			250,000			—
Retirement of long-term debt	(101,064		)	(121,064		)	(1,064		)
Dividends on common stock	(105,121		)	(96,907		)	(88,584		)
Net change in short term borrowings	21,800			—			—
Make-whole premium on retirement of long-term debt	(13,895		)	(17,872		)	—
Other	(2,017		)	(4,775		)	—
Net cash (used in) provided by financing activities	(80,297		)	9,382			(89,648		)
Net (decrease) increase in cash and cash equivalents	(66,616		)	64,061			(19,840		)
Cash and cash equivalents at beginning of the year	110,756			46,695			66,535
Cash and cash equivalents at end of the year	$	44,140		$	110,756		$	46,695
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Income taxes	$	29,341		$	7,487		$	26,116
Interest (net of amount capitalized)	$	78,111		$	79,226		$	77,063
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	34,603		$	23,840		$	28,438

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Consolidated Statements of Retained Earnings



	Year Ended December 31,
	2016			2015			2014
	(thousands of dollars)

Retained Earnings, Beginning of Year	$	1,127,426		$	1,033,350		$	932,547
Net Income	189,242			190,983			189,387
Dividends on Common Stock	(105,121		)	(96,907		)	(88,584		)
Retained Earnings, End of Year	$	1,211,547		$	1,127,426		$	1,033,350

The accompanying notes are an integral part of these statements.

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IDACORP, INC. AND IDAHO POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

This Annual Report on Form 10-K is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power). Therefore, these Notes to the Consolidated Financial Statements apply to both IDACORP and Idaho Power. However, Idaho Power makes no representation as to the information relating to IDACORP’s other operations.

Nature of Business

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sales, and purchase of electric energy and capacity with a service area covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power is regulated primarily by the state utility regulatory commissions of Idaho and Oregon and the Federal Energy Regulatory Commission (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.

IDACORP’s other wholly-owned subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy Services Co. (IESCo), which is the former limited partner of, and current successor by merger to, IDACORP Energy L.P., a marketer of energy commodities that wound down operations in 2003.

Principles of Consolidation

IDACORP’s and Idaho Power’s consolidated financial statements include the assets, liabilities, revenues and expenses of each company and its wholly-owned subsidiaries listed above, as well as any variable interest entities (VIEs) for which the respective company is the primary beneficiary. Investments in VIEs for which the companies are not the primary beneficiaries, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method of accounting.

IDACORP also consolidates one variable interest entity (VIE), Marysville Hydro Partners (Marysville), which is a joint venture owned 50 percent by Ida-West and 50 percent by Environmental Energy Company (EEC). At December 31, 2016 , Marysville had approximately $18 million of assets, primarily a hydroelectric plant, and approximately $11 million of intercompany long-term debt, which is eliminated in consolidation. EEC has borrowed amounts from Ida-West to fund a portion of its required capital contributions to Marysville. The loans are payable from EEC’s share of distributions from Marysville and are secured by the stock of EEC and EEC’s interest in Marysville. Ida-West is identified as the primary beneficiary because the combination of its ownership interest in the joint venture with the intercompany note and the EEC note result in Ida-West's ability to control the activities of the joint venture. Creditors of Marysville have no recourse to the general credit of IDACORP and there are no other arrangements that could require IDACORP to provide financial support to Marysville or expose IDACORP to losses.

The BCC joint venture is also a VIE, but because the power to direct the activities that most significantly impact the economic performance of BCC is shared with the joint venture partner, Idaho Power is not the primary beneficiary. The carrying value of BCC was $82 million at December 31, 2016 , and Idaho Power's maximum exposure to loss is the carrying value, any additional future contributions to BCC, and a $71 million guarantee for mine reclamation costs, which is discussed further in Note 9.

IFS's affordable housing limited partnership and other real estate investments are also VIEs for which IDACORP is not the primary beneficiary. IFS's limited partnership interests range from 2 to 99 percent and were acquired between 1996 and 2010. As a limited partner, IFS does not control these entities and they are not consolidated. IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $8 million at December 31, 2016 .

Ida-West's other investments in PURPA facilities, BCC, and IFS's investments are accounted for under the equity method of accounting (see Note 14).

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Except for amounts related to sales of electricity by Ida-West's PURPA projects to Idaho Power, all intercompany transactions and balances have been eliminated in consolidation.

The accompanying consolidated financial statements include Idaho Power's proportionate share of utility plant and related operations resulting from its interests in jointly owned plants (see Note 12).

Regulation of Utility Operations

As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental

agencies, including the prices that Idaho Power is authorized to charge for its electric service. These approvals are a critical

factor in determining IDACORP's and Idaho Power's results of operations and financial condition.

IDACORP’s and Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. The application of accounting principles related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. In these instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet and recorded on the income statement when recovered or returned in rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers that are expected to be refunded. The effects of applying these regulatory accounting principles to Idaho Power’s operations are discussed in more detail in Note 3.

Management Estimates

Management makes estimates and assumptions when preparing financial statements in conformity with generally accepted accounting principles. These estimates and assumptions include those related to rate regulation, retirement benefits, contingencies, litigation, asset impairment, income taxes, unbilled revenues, and bad debt. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management’s control. Accordingly, actual results could differ from those estimates.

System of Accounts

The accounting records of Idaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility commissions of Idaho, Oregon, and Wyoming.

Cash and Cash Equivalents

Cash and cash equivalents include cash on-hand and highly liquid temporary investments that mature within 90 days of the date of acquisition.

Receivables and Allowance for Uncollectible Accounts

Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of one percent may be assessed on account balances after 30 days. An allowance is recorded for potential uncollectible accounts. The allowance is reviewed periodically and adjusted based upon a combination of historical write-off experience, aging of accounts receivable, and an analysis of specific customer accounts. Adjustments are charged to income. Customer accounts receivable balances that remain outstanding after reasonable collection efforts are written off.

Other receivables, primarily notes receivable from business transactions, are also reviewed for impairment periodically, based upon transaction-specific facts. When it is probable that IDACORP or Idaho Power will be unable to collect all amounts due according to the contractual terms of the agreement, an allowance is established for the estimated uncollectible portion of the receivable and charged to income.

There were no impaired receivables without related allowances at December 31, 2016 and 2015 . Once a receivable is determined to be impaired, any further interest income recognized is fully reserved.

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Derivative Financial Instruments

Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price risk in the electricity and natural gas markets. All derivative instruments are recognized as either assets or liabilities at fair value on the balance sheet unless they are designated as normal purchases and normal sales. With the exception of forward contracts for the purchase of natural gas for use at Idaho Power's natural gas generation facilities and a nominal number of power transactions, Idaho Power’s physical forward contracts are designated as normal purchases and normal sales. Because of Idaho Power’s regulatory accounting mechanisms, Idaho Power records the changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.

Revenues

Operating revenues related to Idaho Power’s sale of energy are recorded when service is rendered or energy is delivered to customers. Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed at year-end. In addition, regulatory mechanisms in place in Idaho and Oregon affect the reported amount of revenue. See Note 3 for additional discussion of certain of the following mechanisms:


•	energy efficiency riders to fund energy efficiency program expenditures. Expenditures funded through the riders are reported as an operating expense with an equal amount of revenues recorded in other revenues;


•	a fixed cost adjustment mechanism that results in recording additional or reduced revenue based on the allowed and actual fixed costs recovered through current rates;


•	a sharing mechanism providing for refunds to customers for earnings above stated returns on equity in Idaho;


•	franchise fees and similar taxes related to energy consumption. None of these collections are reported on the income statement; and


•	collection in base rates of a portion of the allowance for funds used during construction (AFUDC) related to its Hells Canyon Complex (HCC) relicensing project. Cash collected under this ratemaking mechanism is not recorded as revenue but is instead deferred as a regulatory liability.

Property, Plant and Equipment and Depreciation

The cost of utility plant in service represents the original cost of contracted services, direct labor and material, AFUDC, and indirect charges for engineering, supervision, and similar overhead items. Repair and maintenance costs associated with planned major maintenance are expensed as the costs are incurred, as are maintenance and repairs of property and replacements and renewals of items determined to be less than units of property. For utility property replaced or renewed, the original cost plus removal cost less salvage is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to property, plant and equipment.

All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation provisions as a percent of average depreciable utility plant in service approximated 2.64 percent in 2016 and 2.68 percent in both 2015 and 2014 .

During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as construction work in progress on the consolidated balance sheets. If the project becomes probable of being abandoned, such costs are expensed in the period such determination is made. Idaho Power may seek recovery of such costs in customer rates, although there can be no guarantee such recovery would be granted.

Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the undiscounted expected future cash flows from an asset is less than the carrying value of the asset, impairment is recognized in the financial statements. There were no material impairments of long-lived assets in 2016 , 2015 , or 2014 .

Allowance for Funds Used During Construction

AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, as discussed above for the HCC relicensing project, cash is not realized currently from such allowance; it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to total

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interest expense. Idaho Power’s weighted-average monthly AFUDC rate was 7.6 percent for 2016 and 2015 and 7.7 percent for 2014 .

Income Taxes

IDACORP and Idaho Power account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method (commonly referred to as normalized accounting), deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. In general, deferred income tax expense or benefit for a reporting period is recognized as the change in deferred tax assets and liabilities from the beginning to the end of the period. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date unless Idaho Power's primary regulator, the Idaho Public Utilities Commission (IPUC), orders direct deferral of the effect of the change in tax rates over a longer period of time.

Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not provide deferred income taxes for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income tax rate is impacted as these differences arise and reverse. Regulated enterprises are required to recognize such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates.

In compliance with the federal income tax requirements for the use of accelerated tax depreciation, Idaho Power provides deferred income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial statement purposes. Deferred income taxes are provided for other temporary differences unless accounted for using flow-through.

The state of Idaho allows a three percent investment tax credit on qualifying plant additions. Investment tax credits earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties. Credits earned on non-regulated assets or investments are recognized in the year earned.

Income taxes are discussed in more detail in Note 2.

Other Accounting Policies

Debt discount, expense, and premium are deferred and amortized over the terms of the respective debt issues. Losses on reacquired debt and associated costs are amortized over the life of the associated replacement debt, as allowed under regulatory accounting.

Supplemental Cash Flows Information

In 2015, Idaho Power executed an agreement to exchange property with another electric utility. Under the terms of the agreement, each party transferred to the other transmission-related equipment with a book value of approximately $44 million . Idaho Power received an immaterial amount of cash, representing the difference in the book value of the assets exchanged. Also in 2015, Idaho Power executed a long-term service agreement and transferred to the service provider approximately $22 million of spare parts in partial exchange for future services. No cash was exchanged in the 2015 transfer transaction.

Reclassifications

In these consolidated financial statements, certain immaterial amounts in prior periods' consolidated financial statements and footnotes have been reclassified to conform with the current period presentation.

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New and Recently Adopted Accounting Pronouncements

Recently Adopted Accounting Pronouncements

In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-09, Compensation--Stock Compensation (Topic 718) - Improvements to Employer Share-Based Payment Accounting, simplifying several aspects of the accounting for stock compensation paid to employees. As allowed, IDACORP and Idaho Power elected to early adopt the provisions of the new standard in the first quarter of 2016 under the modified retrospective method, with the cumulative effect of adoption recorded as an adjustment to 2016 beginning retained earnings. The principal changes under the new accounting standard include the following:


•	Excess or deficit income tax benefits on share-based transactions are recorded as income tax expense rather than in additional-paid-in-capital.


•	Previously recorded forfeiture estimates of approximately $0.2 million are reported as a decrease to beginning retained earnings. IDACORP made an accounting policy election to account for share-based award forfeitures as they occur, rather than making an estimate of future forfeitures.


•	In the statement of cash flows, excess tax benefits on share-based payments are presented in operating activities in the same manner as other cash flows related to income taxes. Previously, these cash flows were presented in financing activities. Prior periods were not restated for this change.

In May 2015, the FASB issued ASU 2015-07, Fair Value Measurement (Topic 820) - Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) , which removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. As required, IDACORP and Idaho Power have adopted the provisions of this ASU at December 31, 2016, and accordingly, have retrospectively adjusted prior periods.

In February 2015, the FASB issued ASU 2015-02, C onsolidation (Topic 810) - Amendments to the Consolidation Analysis, which revises the consolidation model that reporting entities use when determining what entities are to be consolidated. The amendments focus on limited partnerships and similar legal entities. The adoption of ASU 2015-02 in the first quarter of 2016 did not have a material impact on IDACORP's or Idaho Power's financial statements.

Recent Accounting Pronouncements Not Yet Adopted

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) . ASU 2014-09 is intended to enable users of financial statements to better understand and consistently analyze an entity's revenue across industries, transactions, and geographies. Under the ASU, recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the ASU requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB amended certain aspects of ASU 2014-09 to clarify the implementation guidance, including clarifications related to principal versus agent considerations, licensing and identifying performance obligations, narrow scope improvements, and practical expedients. The companies continue to assess the impacts of ASU 2014-09 on their financial statements, including disclosure requirements, but the companies do not expect the new guidance to significantly affect revenue recognition for tariff-based sales, which represent a significant majority of the companies' general business revenue. Accordingly, the companies do not expect the adoption of ASU 2014-09 to have a material effect on their financial statements; however, a number of industry-specific implementation issues are still unresolved and the final resolution of these issues could affect the companies' accounting for contributions in aid of construction, sales of renewable energy credits, alternative revenue programs, and recognition of revenue when collectability is in question. The guidance in ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2017, including interim periods. The guidance permits two implementation approaches, one requiring retrospective application of the new standard with restatement of prior years (full retrospective approach) and one requiring prospective application of the new standard including a cumulative-effect adjustment with disclosure of results under previous standards (modified-retrospective approach). IDACORP and Idaho Power plan to adopt ASU 2014-09 on January 1, 2018, using the modified-retrospective approach.

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In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), intended to improve financial reporting about leasing transactions. The ASU significantly changes the accounting model used by lessees to account for leases, requiring that all material leases be presented on the balance sheet. Under the current model, some leases are classified as capital leases and recorded on the balance sheet while other leases classified as operating leases are not recognized on the balance sheet. The new standard is effective for annual reporting periods beginning after December 15, 2018, including interim periods, with early adoption permitted. The standard must be adopted using a modified-retrospective approach. IDACORP and Idaho Power are evaluating the impact of ASU 2016-02 on their financial statements. At this time, the companies do not know, and cannot reasonably estimate, the dollar impact of the adoption. Specifically, the companies are considering whether the new guidance will affect their accounting for purchase power agreements, easements and rights-of-way, utility pole attachments, and other utility industry-related areas.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) , which amends ASC 230 to clarify guidance on the classification of certain cash receipts and payments in the statement of cash flows. The FASB issued the ASU with the intent of reducing diversity in practice with respect to eight types of cash flows. The companies expect the ASU to affect the classification of proceeds from the settlement of corporate-owned life insurance policies and related costs, which will be classified as investing activities under the new guidance. The companies already present debt prepayment and extinguishment costs, proceeds from the settlement of insurance claims (other than corporate-owned life insurance), and distributions received from equity-method investments in accordance with the new guidance. ASU 2016-15 is effective for annual reporting periods beginning after December 15, 2017, including interim periods, with early adoption permitted one year earlier. IDACORP and Idaho Power do not plan to early adopt the standard. The standard must be adopted retrospectively to all periods presented, unless impracticable to do so. IDACORP and Idaho Power do not believe the adoption will have a material impact on their financial statements.

2. INCOME TAXES

A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:



	IDACORP									Idaho Power
	2016			2015			2014			2016			2015			2014
	(thousands of dollars)
Federal income tax expense at 35% statutory rate	$	82,151		$	84,154		$	73,588		$	79,250		$	83,724		$	73,116
Change in taxes resulting from:
AFUDC	(11,278		)	(11,140		)	(9,238		)	(11,278		)	(11,140		)	(9,238		)
Capitalized interest	2,000			2,693			2,278			2,000			2,693			2,278
Investment tax credits	(2,922		)	(2,963		)	(3,002		)	(2,922		)	(2,963		)	(3,002		)
Removal costs	(5,559		)	(4,807		)	(3,656		)	(5,559		)	(4,807		)	(3,656		)
Capitalized overhead costs	(10,500		)	(8,750		)	(8,750		)	(10,500		)	(8,750		)	(8,750		)
Capitalized repair costs	(28,000		)	(28,700		)	(26,250		)	(28,000		)	(28,700		)	(26,250		)
Bond redemption costs	(4,997		)	(6,459		)	—			(4,997		)	(6,459		)	—
Tax method change – capitalized repairs ⁽¹⁾	—			—			(24,516		)	—			—			(24,516		)
State income taxes, net of federal benefit	5,071			7,343			4,680			4,880			7,503			5,334
Depreciation	18,673			17,149			16,040			18,673			17,149			16,040
Share-based compensation	(1,614		)	—			—			(1,583		)	—			—
Affordable housing tax credits	(2,579		)	(3,258		)	(5,189		)	—			—			—
Affordable housing investment distributions	(1,717		)	—			—			—			—			—
Affordable housing investment amortization	1,380			1,519			2,757			—			—			—
Other, net	(3,680		)	(1,021		)	(1,970		)	(2,779		)	(22		)	(1,840		)
Total income tax expense	$	36,429		$	45,760		$	16,772		$	37,185		$	48,228		$	19,516
Effective tax rate	15.5%			19.0%			8.0%			16.4%			20.2%			9.3%

⁽¹⁾ In 2014, Idaho Power finalized an income tax accounting method change for the electric generation property portion of its capitalized repairs tax method and the final tangible property regulations. The cumulative impact of the method changes resulted in a net flow-through income tax benefit for 2014. The IRS approved the method changes as part of IDACORP's Compliance Assurance Process (CAP) examinations.

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The items comprising income tax expense are as follows:



	IDACORP									Idaho Power
	2016			2015			2014			2016			2015			2014
	(thousands of dollars)
Income taxes current:
Federal	$	1,181		$	4,831		$	(4,926	)	$	7,639		$	16,470		$	(2,805	)
State	2,158			2,704			3,516			3,766			6,056			6,867
Total	3,339			7,535			(1,410		)	11,405			22,526			4,062
Income taxes deferred:
Federal	33,205			34,770			17,159			27,506			27,696			21,833
State	100			626			(3,260		)	(2,031		)	(2,486		)	(6,421		)
Total	33,305			35,396			13,899			25,475			25,210			15,412
Investment tax credits:
Deferred	3,227			3,455			3,044			3,227			3,455			3,044
Restored	(2,922		)	(2,963		)	(3,002		)	(2,922		)	(2,963		)	(3,002		)
Total	305			492			42			305			492			42
Affordable housing investments	(520		)	2,337			4,241			—			—			—
Total income tax expense	$	36,429		$	45,760		$	16,772		$	37,185		$	48,228		$	19,516

The components of the net deferred tax liability are as follows:



	IDACORP				Idaho Power
	2016		2015		2016		2015
	(thousands of dollars)
Deferred tax assets:
Regulatory liabilities	$	51,326	$	51,131	$	51,326	$	51,131
Deferred compensation	29,490		27,573		29,424		27,489
Deferred revenue	40,354		34,282		40,354		34,282
Tax credits	142,627		147,299		33,589		30,307
Partnership investments	6,543		7,220		—		—
Retirement benefits	132,362		126,885		132,362		126,885
Other	11,401		11,245		11,069		10,745
Total	414,103		405,635		298,124		280,839
Deferred tax liabilities:
Property, plant and equipment	500,987		474,879		500,987		474,879
Regulatory assets	948,540		875,028		948,540		875,028
Power cost adjustments	21,077		18,489		21,077		18,489
Fixed cost adjustment	17,376		14,395		17,376		14,395
Partnership investments	12,371		16,925		5,554		9,829
Retirement benefits	140,083		126,090		140,083		126,090
Other	17,919		17,205		15,922		14,500
Total	1,658,353		1,543,011		1,649,539		1,533,210
Net deferred tax liabilities	$	1,244,250	$	1,137,376	$	1,351,415	$	1,252,371

IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate company basis. Amounts payable or refundable are settled through IDACORP. See Note 1 for further discussion of accounting policies related to income taxes.

Tax Credit Carryforwards

As of December 31, 2016 , IDACORP had $103.5 million of general business credit carryforwards for federal income tax purposes and $39.1 million of Idaho investment tax credit carryforward. The general business credit carryforward period expires from 2025 to 2036 , and the Idaho investment tax credit expires from 2021 to 2030 .

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Uncertain Tax Positions

IDACORP and Idaho Power believe that they have no material income tax uncertainties for 2016 and prior tax years. Both companies recognize interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense.

IDACORP and Idaho Power are subject to examination by their major tax jurisdictions - U.S. federal and the State of Idaho. The open tax years for examination are 2016 for federal and 2012-2016 for Idaho. In May 2009, IDACORP formally entered the U.S. Internal Revenue Service (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year and has remained in the CAP program for all subsequent years. The CAP program provides for IRS examination and issue resolution throughout the current year with the objective of return filings containing no contested items. In 2016, t he IRS completed its examination of IDACORP's 2015 tax year with no unresolved income tax issues.

3. REGULATORY MATTERS

IDACORP’s and Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. Included below is a summary of Idaho Power's regulatory assets and liabilities, as well as a discussion of notable regulatory matters.

Regulatory Assets and Liabilities

The application of accounting principles related to regulated operations sometimes results in Idaho Power recording some expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from customers through future rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in advance of incurring an expense.

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The following table presents a summary of Idaho Power’s regulatory assets and liabilities (in thousands of dollars):



		As of December 31, 2016
	Remaining Amortization Period	Earning a Return ⁽¹⁾		Not Earning a Return		Total as of December 31,
Description	Remaining Amortization Period	Earning a Return ⁽¹⁾		Not Earning a Return		2016		2015
Regulatory Assets:
Income taxes		$	—	$	948,540	$	948,540	$	875,027
Unfunded postretirement benefits ⁽²⁾		—		263,779		263,779		251,762
Pension expense deferrals		83,057		22,295		105,352		85,790
Energy efficiency program costs ⁽³⁾		5,552		—		5,552		4,482
Power supply costs ⁽⁴⁾	2017-2018	53,870		—		53,870		47,220
Fixed cost adjustment ⁽⁴⁾	2017-2018	44,445		—		44,445		36,820
Asset retirement obligations ⁽⁵⁾		—		14,154		14,154		14,410
Mark-to-market liabilities ⁽⁶⁾		—		—		—		4,973
Long-term service agreement ⁽⁷⁾	2043	17,879		11,202		29,081		30,225
Other	2017-2054	2,541		4,585		7,126		3,716
Total		$	207,344	$	1,264,555	$	1,471,899	$	1,354,425
Regulatory Liabilities:
Income taxes		$	—	$	51,326	$	51,326	$	51,131
Removal costs ⁽⁵⁾		—		186,609		186,609		183,505
Investment tax credits		—		79,960		79,960		79,655
Deferred revenue-AFUDC ⁽⁸⁾		70,178		33,041		103,219		87,690
Energy efficiency program costs ⁽³⁾		10,730		—		10,730		6,554
Settlement agreement sharing mechanism ⁽⁴⁾		—		—		—		3,159
Mark-to-market assets ⁽⁶⁾		—		7,831		7,831		405
Other		5,598		1,516		7,114		6,399
Total		$	86,506	$	360,283	$	446,789	$	418,498

⁽¹⁾ Earning a return includes either interest or a return on the investment as a component of rate base at the allowed rate of return.

⁽²⁾ Represents the unfunded obligation of Idaho Power’s pension and postretirement benefit plans, which are discussed in Note 11.

⁽³⁾ The energy efficiency asset represents the Oregon jurisdiction balance and the liability represents the Idaho jurisdiction balance.

⁽⁴⁾ These items are discussed in more detail in this Note 3.

⁽⁵⁾ Asset retirement obligations and removal costs are discussed in Note 13.

⁽⁶⁾ Mark-to-market assets and liabilities are discussed in Note 16.

⁽⁷⁾ A portion not earning a return as of December 31, 2016, will be eligible to earn a return as of January 1, 2018.

⁽⁸⁾ Idaho Power is collecting revenue in the Idaho jurisdiction for AFUDC on HCC relicensing costs 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.

Idaho Power’s regulatory assets and liabilities are typically amortized over the period in which they are reflected in customer rates. In the event that recovery of Idaho Power’s costs through rates becomes unlikely or uncertain, regulatory accounting would no longer apply to some or all of Idaho Power’s operations and the items above may represent stranded investments. If not allowed full recovery of these items, Idaho Power would be required to write off the applicable portion, which could have a materially adverse financial impact.

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Power Cost Adjustment Mechanisms and Deferred Power Supply Costs

In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment mechanisms address the volatility of power supply costs and provide for annual adjustments to the rates charged to its retail customers. The power cost adjustment mechanisms compare Idaho Power's actual net power supply costs (primarily fuel and purchased power less off-system sales) against net power supply costs being recovered in Idaho Power's retail rates. Under the power cost adjustment mechanisms, certain differences between actual net power supply costs incurred by Idaho Power and costs being recovered in retail rates are recorded as a deferred charge or credit on the balance sheets for future recovery or refund. The power supply costs deferred primarily result from changes in contracted power purchase prices and volumes, changes in wholesale market prices and transaction volumes, fuel prices, and the levels of Idaho Power's own generation. The Idaho deferral period or PCA year runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period.

Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual PCA adjustment consists of (a) a forecast component, based on a forecast of net power supply costs in the coming year as compared with net power supply costs included in base rates; and (b) a true-up component, based on the difference between the previous year’s actual net power supply costs and the previous year’s forecast. The latter component also includes a balancing mechanism so that, over time, the actual collection or refund of authorized true-up dollars matches the amounts authorized. The PCA mechanism also includes:


•	a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers ( 95 percent ) and shareholders ( 5 percent ), with the exceptions of expenses associated with PURPA power purchases and demand response incentive payments, which are allocated 100 percent to customers; and


•	a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales changes does not distort the results of the mechanism.

The table below summarizes the three most recent PCA rate adjustments, all of which also include non-PCA-related rate adjustments as ordered by the IPUC:



Effective Date	$ Change (millions)			Notes
June 1, 2016	$	17.3		The net increase in PCA rates included the application of (a) a customer rate credit of $3.2 million for sharing of revenues with customers for the year 2015 under the terms of the October 2014 settlement stipulation, and (b) $4.0 million reduction due to the transfer of Idaho energy efficiency rider funds.
June 1, 2015	$	(11.6	)	The net decrease in PCA rates included the application of (a) a customer rate credit of $8.0 million for sharing of revenues with customers for the year 2014 under the terms of the December 2011 settlement stipulation, and (b) $4.0 million of surplus Idaho energy efficiency rider funds.
June 1, 2014	$	(88.2	)	2014 PCA rates are net of (a) $20.0 million of surplus Idaho energy efficiency rider funds, and (b) $7.6 million of customer revenue sharing under a regulatory settlement stipulation. In addition, on June 1, 2014, there was an increase in base net power supply costs that shifted $99.3 million in power supply expenses from recovery via the PCA mechanism to recovery via base rates. The shifting of base net power supply costs is discussed in more detail below.

In March 2014, the IPUC issued an order approving Idaho Power's application requesting an increase of approximately $106 million in the normalized or "base level" net power supply expense on a total-system basis to be used to update base rates and in the determination of the PCA rate that became effective June 1, 2014. Approval of the order removed the Idaho-jurisdictional portion of those expenses (approximately $99 million ) from collection via the PCA mechanism and instead results in collecting that portion through base rates.

In July 2014, the IPUC opened a docket pursuant to which Idaho Power, the IPUC Staff, and other interested parties further evaluated Idaho Power's application of the true-up component of the PCA mechanism and whether a deferral balance adjustment was appropriate. While the IPUC's docket was closed in August 2014 with no adjustment to the PCA true-up revenue amount, Idaho Power subsequently met with the IPUC Staff to explore approaches to increasing the accuracy of the actual cost recovery under the PCA mechanism. In May 2015, the IPUC approved a settlement stipulation that resulted in the replacement of the existing load-based adjustment used for determining the power cost deferrals under the PCA mechanism with a similar sales-based adjustment. The sales-based adjustment functions in the same manner as the previous load-based adjustment but measures deviations between Idaho-specific test year sales and actual Idaho sales rather than deviations between test year loads and actual loads. The approved settlement stipulation implemented the new methodology as of January 1, 2015.

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Oregon Jurisdiction Power Cost Adjustment Mechanism: Idaho Power’s power cost recovery mechanism in Oregon has two components: an annual power cost update (APCU) and a power cost adjustment mechanism (PCAM). The APCU allows Idaho Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net power supply expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for the same period. Under the PCAM, Idaho Power is subject to a portion of the business risk or benefit associated with this deviation through application of an asymmetrical deadband (or range of deviations) within which Idaho Power absorbs cost increases or decreases. For deviations in actual power supply costs outside of the deadband, the PCAM provides for 90 / 10 sharing of costs and benefits between customers and Idaho Power. However, collection by Idaho Power will occur only to the extent that Idaho Power’s actual Oregon-jurisdictional return on equity (Oregon ROE) for the year is no greater than 100 basis points below Idaho Power’s last authorized Oregon ROE. A refund to customers will occur only to the extent that Idaho Power’s actual Oregon ROE for that year is no less than 100 basis points above Idaho Power’s last authorized Oregon ROE. Oregon jurisdiction power supply cost changes under the APCU and PCAM during each of 2016, 2015, and 2014 are summarized in the table that follows:



Year and Mechanism		APCU or PCAM Adjustment
2016 PCAM		Actual net power supply costs were within the deadband, resulting in no deferral.
2016 APCU		A rate increase of $0.2 million annually took effect June 1, 2016.
2015 PCAM		Actual net power supply costs were within the deadband, resulting in no deferral.
2015 APCU		A rate decrease of $0.7 million annually took effect June 1, 2015.
2014 PCAM		Actual net power supply costs were within the deadband, resulting in no deferral.
2014 APCU		A rate increase of $0.4 million annually took effect June 1, 2014.

Notable Idaho Regulatory Matters

Idaho Base Rate Changes: Idaho base rates were most recently established in 2012, and adjusted in 2014. Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from IPUC approval of a settlement stipulation that provided for a 7.86 percent authorized overall rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion . The settlement stipulation resulted in a 4.07 percent , or $34.0 million , overall increase in Idaho Power's annual Idaho-jurisdiction base rate revenues. Idaho base rates were subsequently adjusted again in 2012, in connection with Idaho Power's completion of the Langley Gulch power plant. In June 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdiction base rates, effective July 1, 2012. The order also provided for a $335.9 million increase in Idaho rate base. Neither the settlement stipulation nor the IPUC orders adjusting base rates specified an authorized rate of return on equity or imposed a moratorium on Idaho Power filing a general rate case at a future date.

As noted above in this Note 3, the IPUC also issued a March 2014 order approving Idaho Power's request for an increase in the normalized or "base level" net power supply expense to be used to update base rates and in the determination of the PCA rate that became effective June 1, 2014.

December 2011 Idaho Settlement Stipulation: In December 2011, the IPUC issued an order, separate from the then-pending general rate case proceeding, approving a settlement stipulation that provided as follows:


•	If Idaho Power's actual Idaho-jurisdiction return on year-end equity (Idaho ROE) for 2012, 2013, or 2014 was less than 9.5 percent , then Idaho Power could amortize up to a total of $45 million of additional accumulated deferred investment tax credits (ADITC) to help achieve a minimum 9.5 percent Idaho ROE in the applicable year.

•

If Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeded 10.0 percent , the amount of Idaho Power's Idaho-jurisdiction earnings exceeding a 10.0 percent and up to and including a 10.5 percent Idaho ROE for the applicable year would be shared equally between Idaho Power and its Idaho customers in the form of a rate reduction to become effective at the time of the subsequent year's PCA mechanism adjustment.


•	If Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeded 10.5 percent , the amount of Idaho Power's Idaho jurisdictional earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 75 percent to Idaho Power's Idaho customers as a reduction to the pension regulatory asset and 25 percent to Idaho Power.

As Idaho Power's Idaho ROE exceeded 10.5 percent in 2014, Idaho Power did not amortize additional ADITC, but instead shared $24.7 million of its Idaho-jurisdiction earnings with Idaho customers. Of the amount shared in 2014, $8.0 million was

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returned as a rate reduction as part of the 2015 PCA mechanism adjustment and $16.7 million was recorded as a pre-tax charge to pension expense .

October 2014 Idaho Settlement Stipulation: In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of the December 2011 Idaho settlement stipulation for the period from 2015 through 2019, or until the terms are otherwise modified or terminated by order of the IPUC or the full $45 million of additional ADITC contemplated by the settlement stipulation has been amortized. The provisions of the new settlement stipulation are as follows:


•	If Idaho Power's annual Idaho ROE in any year is less than 9.5 percent , then Idaho Power may amortize up to $25 million of additional ADITC to help achieve a 9.5 percent Idaho ROE for that year, and may amortize up to a total of $45 million of additional ADITC over the 2015 through 2019 period.


•	If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent , the amount of earnings exceeding a 10.0 percent Idaho ROE and up to and including a 10.5 percent Idaho ROE will be allocated 75 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA and 25 percent to Idaho Power.

•

If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent , the amount of earnings exceeding a 10.5 percent Idaho ROE will be allocated 50 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension expense deferral regulatory asset (to reduce the amount to be collected in the future from Idaho customers), and 25 percent to Idaho Power.


•	If the full $45 million of additional ADITC contemplated by the settlement stipulation has been amortized the sharing provisions would terminate.


•	In the event the IPUC approves a change to Idaho Power's Idaho-jurisdictional allowed return on equity as part of a general rate case proceeding seeking a rate change effective prior to January 1, 2020, the Idaho ROE thresholds ( 9.5 percent , 10.0 percent , and 10.5 percent ) will be adjusted prospectively.

Neither the settlement stipulation nor the associated IPUC order impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding during the term of the settlement stipulation.

In 2015, Idaho Power recorded a $3.2 million provision against current revenue for sharing with customers, as its Idaho ROE for 2015 was above 10.0 percent . In 2016, Idaho Power recorded no additional ADITC amortization and no provision for sharing with customers, as its 2016 Idaho ROE was between 9.5 percent and 10.0 percent . Accordingly, at December 31, 2016, the full $45 million of additional ADITC remains available for future use under the terms of the settlement stipulation.

In 2016, 2015, and 2014, Idaho Power recorded the following for sharing with customers under the December 2011 and October 2014 Idaho settlement stipulations (in millions):



Year	Recorded as Refunds to Customers	Recorded as a Pre-tax Charge to Pension Expense
2016	$—	$—
2015	$3.2	$—
2014	$8.0	$16.7

Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (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 and linking it instead to a set amount per customer. The FCA mechanism is adjusted each year to collect, or refund, the difference between the authorized fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the year. The annual change in the FCA recovery is capped at no more than 3 percent of base revenue, with any excess deferred for collection in a subsequent year.

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The following table summarizes FCA amounts approved for collection in the prior three FCA years:



FCA Year	Period Rates in Effect	Annual Amount (in millions)
2015	June 1, 2016-May 31, 2017	$28.1
2014	June 1, 2015-May 31, 2016	$16.9
2013	June 1, 2014-May 31, 2015	$14.9

In July 2014, the IPUC opened a docket to allow Idaho Power, the IPUC Staff, and other interested parties to further evaluate the IPUC Staff's concerns regarding the application of the FCA mechanism (including weather-normalization, customer count methodology, rate adjustment cap, and cross-subsidization issues) and whether the FCA is effectively removing Idaho Power's disincentive to aggressively pursue energy efficiency programs. In May 2015, the IPUC approved a settlement stipulation that modified the FCA mechanism by replacing weather-normalized billed sales with actual billed sales in the calculation of the FCA, applicable for the entirety of calendar year 2015 and thereafter, and reflected in FCA charges effective June 1, 2016.

Depreciation Rate Requests

In 2016, Idaho Power conducted a depreciation study of all electric plant-in-service that provided updates to net salvage percentages and service life estimates for all Idaho Power plant assets. Based on the study, in October and November 2016, Idaho Power filed applications with the IPUC and OPUC, respectively, requesting approval to institute revised depreciation rates for Idaho Power's electric plant-in-service and adjust base rates by an aggregate of $7.4 million to reflect the revised depreciation rates applied to electric plant in service balances subject to the most recent general rate cases. The proposed adjustments in these applications are an overall rate increase of 0.6 percent in Idaho and 1.3 percent in Oregon.

At the same time, Idaho Power also filed applications with the IPUC and the OPUC requesting authorization to (a) accelerate depreciation for the North Valmy coal-fired power plant, to allow the plant to be fully depreciated by December 31, 2025, (b) establish a balancing account to track the incremental costs and benefits associated with the accelerated depreciation date, and (c) adjust customer rates to recover the associated incremental annual levelized revenue requirement in the aggregate amount of $29.6 million . The proposed adjustment in these applications are an overall rate increase of 2.5 percent in Idaho and 1.9 percent in Oregon.

Idaho Power expects the IPUC and the OPUC to enter final orders in both matters prior to June 2017 in Idaho and November 2017 in Oregon.

Western Energy Imbalance Market Costs

Idaho Power plans to participate in a new energy imbalance market implemented in the western United States (Western EIM). In August 2016, Idaho Power filed an application with the IPUC requesting specified regulatory accounting treatment associated with its participation in the Western EIM. In January 2017, the IPUC issued an order authorizing Idaho Power’s requested deferral accounting treatment for costs associated with joining the Western EIM. Idaho Power can defer costs incurred until the earlier of when Idaho Power requests recovery of the costs and the deferral balance or the end of 2018. Recovery of deferred costs will be addressed in a future IPUC proceeding. Idaho Power anticipates that its participation in the Western EIM will commence in the spring of 2018.

Notable Oregon Regulatory Matters

Oregon Base Rate Changes: Oregon base rates were most recently established in a general rate case in 2012. In February 2012, the OPUC issued an order approving a settlement stipulation that provided for a $1.8 million base rate increase, a return on equity of 9.9 percent , and an overall rate of return of 7.757 percent in the Oregon jurisdiction. New rates in conformity with the settlement stipulation were effective March 1, 2012. Subsequently, in September 2012, the OPUC issued an order approving an approximately $3.0 million increase in annual Oregon jurisdiction base rates, effective October 1, 2012, for inclusion of the Langley Gulch power plant in Idaho Power's Oregon rate base.

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Federal Regulatory Matters - Open Access Transmission Tariff Rates

Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on financial and operational data Idaho Power files with the FERC. Idaho Power's OATT rates submitted to the FERC in Idaho Power's four most recent annual OATT Final Informational Filings were as follows:



Applicable Period	OATT Rate (per kW-year)
October 1, 2016 to September 30, 2017	$	25.52
October 1, 2015 to September 30, 2016	$	23.43
October 1, 2014 to September 30, 2015	$	22.48
October 1, 2013 to September 30, 2014	$	22.80

Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $127.4 million , which represents the OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.

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4. LONG-TERM DEBT

The following table summarizes IDACORP's and Idaho Power's long-term debt at December 31 (in thousands of dollars):



	2016			2015
First mortgage bonds:
6.15% Series due 2019	$	—		$	100,000
4.50% Series due 2020	130,000			130,000
3.40% Series due 2020	100,000			100,000
2.95% Series due 2022	75,000			75,000
2.50% Series due 2023	75,000			75,000
6.00% Series due 2032	100,000			100,000
5.50% Series due 2033	70,000			70,000
5.50% Series due 2034	50,000			50,000
5.875% Series due 2034	55,000			55,000
5.30% Series due 2035	60,000			60,000
6.30% Series due 2037	140,000			140,000
6.25% Series due 2037	100,000			100,000
4.85% Series due 2040	100,000			100,000
4.30% Series due 2042	75,000			75,000
4.00% Series due 2043	75,000			75,000
3.65% Series due 2045	250,000			250,000
4.05% Series due 2046	120,000			—
Total first mortgage bonds	1,575,000			1,555,000
Pollution control revenue bonds:
5.15% Series due 2024 ⁽¹⁾	49,800			49,800
5.25% Series due 2026 ⁽¹⁾	116,300			116,300
Variable Rate Series 2000 due 2027	4,360			4,360
Total pollution control revenue bonds	170,460			170,460
American Falls bond guarantee	19,885			19,885
Milner Dam note guarantee	1,064			2,127
Unamortized issuance costs and discounts	(20,731		)	(20,998		)
Total IDACORP and Idaho Power outstanding debt ⁽²⁾	1,745,678			1,726,474
Current maturities of long-term debt	(1,064		)	(1,064		)
Total long-term debt	$	1,744,614		$	1,725,410

⁽¹⁾ Humboldt County and Sweetwater County Pollution Control Revenue Bonds are secured by the first mortgage, bringing the total first mortgage bonds outstanding at December 31, 2016 , to $1.741 billion .

⁽²⁾ At December 31, 2016 and 2015 , the overall effective cost rate of Idaho Power's outstanding debt was 4.87 percent and 4.96 percent , respectively.

At December 31, 2016 , the maturities for the aggregate amount of IDACORP and Idaho Power long-term debt outstanding were as follows (in thousands of dollars):



2017		2018		2019		2020		2021		Thereafter
$	1,064	$	—	$	—	$	230,000	$	—	$	1,535,345

Long-Term Debt Issuances, Maturities, and Availability

On March 10, 2016, Idaho Power issued $120 million in principal amount of 4.05% first mortgage bonds, secured medium-term notes, Series J, maturing on March 1, 2046. On April 11, 2016, Idaho Power redeemed, prior to maturity, $100 million in principal amount of 6.15% first mortgage bonds, medium-term notes, Series H, due April 2019. In accordance with the redemption provisions of the notes, the redemption included Idaho Power's payment of a make-whole premium to the holders

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of the redeemed notes in the aggregate amount of approximately $14.0 million . Idaho Power used a portion of the net proceeds from the March 2016 sale of first mortgage bonds, medium-term notes to effect the redemption.

On March 6, 2015, Idaho Power issued $250 million in principal amount of 3.65% first mortgage bonds, secured medium-term notes, Series J, maturing on March 1, 2045. On April 23, 2015, Idaho Power redeemed, prior to maturity, $120 million in principal amount of 6.025% first mortgage bonds, secured medium-term notes, Series H, due July 2018. In accordance with the redemption provisions of the notes, the redemption included Idaho Power's payment of a make-whole premium to the holders of the redeemed notes in the aggregate amount of approximately $17.9 million . Idaho Power used a portion of the net proceeds from the March 2015 sale of first mortgage bonds, medium-term notes to effect the redemption.

In April and May 2016, Idaho Power received orders from the IPUC, OPUC, and Wyoming Public Service Commission (WPSC) authorizing Idaho Power to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. The order from the IPUC approved the issuance of the securities through May 31, 2019, subject to extensions upon request to the IPUC. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum all-in interest rate limit of 7.0 percent .

On May 20, 2016, IDACORP and Idaho Power filed a joint shelf registration statement with the U.S. Securities and Exchange Commission (SEC), which became effective upon filing, for the offer and sale of, in the case of Idaho Power, an unspecified principal amount of its first mortgage bonds and debt securities. On September 27, 2016, Idaho Power entered into a selling agency agreement with seven banks named in the agreement in connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds, secured medium term notes, Series K (Series K Notes), under Idaho Power’s Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). At the same time, Idaho Power entered into the Forty-eighth Supplemental Indenture, dated as of September 1, 2016, to the Indenture. The Forty-eighth Supplemental Indenture provides for, among other items, the issuance of up to $500 million in aggregate principal amount of Series K Notes pursuant to the Indenture. As of December 31, 2016 , $500 million in principal amount of Series K Notes remained available for issuance under the Indenture.

Mortgage : As of December 31, 2016 , Idaho Power could issue under its Indenture approximately $1.7 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions. These amounts are further limited by the maximum amount of first mortgage bonds set forth in the Indenture.

The mortgage of the Indenture secures all bonds issued under the Indenture equally and ratably, without preference, priority, or distinction. First mortgage bonds issued in the future will also be secured by the mortgage of the Indenture. The lien constitutes a first mortgage on all the properties of Idaho Power, subject only to certain limited exceptions including liens for taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of Idaho Power are subject to easements, leases, contracts, covenants, workmen's compensation awards, and similar encumbrances and minor defects and clouds common to properties. The mortgage of the Indenture does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses in action, except as permitted by law during a completed default, securities, or cash, except when pledged, or merchandise or equipment manufactured or acquired for resale. The mortgage of the Indenture creates a lien on the interest of Idaho Power in property subsequently acquired, other than excepted property, subject to limitations in the case of consolidation, merger, or sale of all or substantially all of the assets of Idaho Power. The Indenture requires Idaho Power to spend or appropriate 15 percent of its annual gross operating revenues for maintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make up these expenditures or appropriations within the five years that immediately follow or precede a particular year.

The Forty-eighth Supplemental Indenture increased the maximum amount of first mortgage bonds issuable by Idaho Power under the Indenture from $2.0 billion to $2.5 billion . The amount issuable is also restricted by property, earnings, and other provisions of the Indenture and supplemental indentures to the Indenture. Idaho Power may amend the Indenture and increase this amount without consent of the holders of the first mortgage bonds. The Indenture requires that Idaho Power's net earnings be at least twice the annual interest requirements on all outstanding debt of equal or prior rank, including the bonds that Idaho Power may propose to issue. Under certain circumstances, the net earnings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than two years or that are of an equal or higher interest rate, or prior lien bonds.

5. NOTES PAYABLE

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Credit Facilities

On November 6, 2015, IDACORP and Idaho Power entered into Credit Agreements replacing the existing Second Amended and Restated Credit Agreements, dated October 26, 2011, to provide credit facilities that may be used for general corporate purposes and commercial paper backup. IDACORP's credit facility consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $100 million , including swingline loans in an aggregate principal amount at any time outstanding not to exceed $10 million , and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million . Idaho Power's credit facility consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the aggregate principal amount at any one time outstanding of $300 million , including swingline loans in an aggregate principal amount at any time outstanding not to exceed $30 million , and letters of credit in an aggregate principal amount at any time outstanding not to exceed $100 million . IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $450 million , respectively, in each case subject to certain conditions.

The IDACORP and Idaho Power credit facilities have similar terms and conditions. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate , federal funds rate plus 0.5 percent , or LIBOR rate plus 1.0 percent , or (2) the LIBOR rate , plus, in each case, an applicable margin, provided that the federal funds rate and LIBOR rate will not be less than 0.0 percent . The margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreements. Under their respective credit facilities, the companies pay a facility fee on the commitment based on the respective company's credit rating for senior unsecured long-term debt securities. While the credit facilities provide for an original maturity date of November 6, 2020, the credit agreements grant IDACORP and Idaho Power the right to request up to two one-year extensions, subject to certain conditions. On November 7, 2016, IDACORP and Idaho Power executed the first extension agreement with the consent of all the lenders, extending the maturity date under both credit agreements to November 5, 2021. No other terms of the credit facilities, included the amount of permitted borrowing under the credit agreements, were affected by the extensions.

At December 31, 2016 , no loans were outstanding under either IDACORP's or Idaho Power's facilities. At December 31, 2016 , Idaho Power had regulatory authority to incur up to $450 million in principal amount of short-term indebtedness at any one time outstanding. Balances (in thousands of dollars) and interest rates of IDACORP’s and Idaho Power's short-term borrowings were as follows at December 31, 2016 , and December 31, 2015 :



	IDACORP						Idaho Power						Total
	2016			2015			2016			2015			2016			2015
Commercial paper balances:
At the end of year	$	—		$	20,000		$	21,800		$	—		$	21,800		$	20,000
Average during the year	$	15,692		$	22,054		$	438		$	—		$	16,130		$	22,054
Weighted-average interest rate
At the end of the year	—		%	0.88		%	1.13		%	—		%	1.13		%	0.88		%

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6. COMMON STOCK

IDACORP Common Stock

The following table summarizes IDACORP common stock transactions during the last three years and shares reserved at December 31, 2016 :



	Shares issued			Shares reserved
	2016	2015	2014	December 31, 2016
Balance at beginning of year	50,352,051	50,308,702	50,233,463
Continuous equity program (inactive)	—	—	—	3,000,000
Dividend reinvestment and stock purchase plan	—	—	—	2,576,723
Employee savings plan	—	—	—	3,567,954
Long-term incentive and compensation plan	67,966	43,349	75,239	1,311,147
Restricted stock plan ⁽¹⁾	—	—	—	256,154
Balance at end of year	50,420,017	50,352,051	50,308,702

⁽¹⁾ The Restricted Stock Plan was terminated on February 9, 2017.

In recent years, IDACORP has entered into sales agency agreements under which IDACORP could offer and sell shares of its common stock from time to time through an agent. The most recent sales agency agreement expired in May 2016, but IDACORP may choose to enter into a new sales agency agreement in the future. On May 20, 2016, IDACORP filed a shelf registration statement with the SEC, which became effective upon filing, for the potential offer and sale of an unspecified amount of shares of common stock.

Restrictions on Dividends

Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants in their respective credit facilities or Idaho Power’s Revised Code of Conduct. A covenant under IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. At December 31, 2016 , the leverage ratios for IDACORP and Idaho Power were 45 percent and 47 percent , respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $1.2 billion and $1.0 billion , respectively, at December 31, 2016 . There are additional facility covenants, subject to exceptions, that prohibit or restrict the sale or disposition of property without consent and any agreements restricting dividend payments to the company from any material subsidiary. At December 31, 2016 , IDACORP and Idaho Power were in compliance with those covenants.

Idaho Power’s Revised Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other affiliates, which was approved by the IPUC in April 2008, provides that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval. At December 31, 2016 , Idaho Power's common equity capital was 53 percent of its total adjusted capital. Further, Idaho Power must obtain approval from the OPUC before it can directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

Idaho Power’s articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. As of the date of this report, Idaho Power has no preferred stock outstanding.

In addition to contractual restrictions on the amount and payment of dividends, the Federal Power Act (FPA) prohibits the payment of dividends from "capital accounts." The term "capital account" is undefined in the FPA or its regulations, but Idaho Power does not believe the restriction would limit Idaho Power's ability to pay dividends out of current year earnings or retained earnings.

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7. STOCK-BASED COMPENSATION

IDACORP has two share-based compensation plans -- the 2000 Long-Term Incentive and Compensation Plan (LTICP) and the 1994 Restricted Stock Plan (RSP). The RSP was terminated effective February 9, 2017. The LTICP (for officers, key employees, and directors) permits the grant of stock options, restricted stock, performance shares, performance units, and several other types of stock-based awards. At December 31, 2016 , the maximum number of shares available under the LTICP and RSP were 934,781 and 15,796 , respectively, excluding (i) issued but unvested performance-based restricted shares and (ii) issued but unvested time-based restricted shares.

Stock Awards: Restricted stock awards have three-year vesting periods and entitle the recipients to dividends and voting rights. Unvested shares are restricted as to disposition and subject to forfeiture under certain circumstances. The fair value of these awards is based on the closing market price of common stock on the grant date and is charged to compensation expense over the vesting period, based on the number of shares expected to vest.

Performance-based restricted stock awards have three-year vesting periods and entitle the recipients to voting rights. Unvested shares are restricted as to disposition, subject to forfeiture under certain circumstances, and subject to the attainment of specific performance conditions over the three-year vesting period. The performance conditions are two equally-weighted metrics, cumulative earnings per share (CEPS) and total shareholder return (TSR) relative to a peer group. Depending on the level of attainment of the performance conditions and the year issued, the final number of shares awarded can range from zero to 150 percent of the target award for awards granted prior to 2015 and from zero to 200 percent of the target award for awards granted in 2015 and 2016. Dividends are accrued during the vesting period and paid out based on the final number of shares awarded.

The grant-date fair value of the CEPS portion is based on the closing market value at the date of grant, reduced by the loss in time-value of the estimated future dividend payments. The fair value of this portion of the awards is charged to compensation expense over the requisite service period, based on the number of shares expected to vest. The grant-date fair value of the TSR portion is estimated using the market value at the date of grant and a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. The fair value of this portion of the awards is charged to compensation expense over the requisite service period, provided the requisite service period is rendered, regardless of the level of TSR metric attained.

A summary of restricted stock and performance share activity is presented below. Idaho Power share amounts represent the portion of IDACORP amounts related to Idaho Power employees:



	IDACORP				Idaho Power
	Number of Shares		Weighted-Average Grant Date Fair Value		Number of Shares		Weighted-Average Grant Date Fair Value
Nonvested shares at January 1, 2016	230,820		$	52.41	228,790		$	52.44
Shares granted	114,486		64.13		113,708		64.18
Shares forfeited	(24,699	)	65.75		(24,699	)	65.75
Shares vested	(119,542	)	44.30		(118,273	)	44.32
Nonvested shares at December 31, 2016	201,065		$	61.49	199,526		$	61.51

The total fair value of shares vested was $8.3 million in 2016 , $8.3 million in 2015 , and $6.6 million in 2014 . At December 31, 2016 , IDACORP had $5.0 million of total unrecognized compensation cost related to nonvested share-based compensation that was expected to vest. Idaho Power’s share of this amount was $4.9 million . These costs are expected to be recognized over a weighted-average period of 1.73 years. IDACORP uses original issue and/or treasury shares for these awards.

In 2016 , a total of 12,681 shares were awarded to directors at a grant date fair value of $70.96 per share. Directors elected to defer receipt of 4,931 of these shares, which are being held as deferred stock units with dividend equivalents reinvested in additional stock units.

Compensation Expense: The following table shows the compensation cost recognized in income and the tax benefits resulting from these plans, as well as the amounts allocated to Idaho Power for those costs associated with Idaho Power’s employees (in thousands of dollars):

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	IDACORP						Idaho Power
	2016		2015		2014		2016		2015		2014
Compensation cost	$	5,561	$	5,299	$	5,609	$	5,494	$	5,221	$	5,458
Income tax benefit	2,174		2,072		2,193		2,148		2,042		2,134

No equity compensation costs have been capitalized. These costs are primarily reported within other operations and maintenance expense in the consolidated statements of income.

8. EARNINGS PER SHARE

The following table presents the computation of IDACORP’s basic and diluted earnings per share for the years ended December 31, 2016 , 2015 , and 2014 (in thousands, except for per share amounts):



	Year Ended December 31,
	2016		2015		2014
Numerator:
Net income attributable to IDACORP, Inc.	$	198,288	$	194,679	$	193,480
Denominator:
Weighted-average common shares outstanding - basic	50,298		50,220		50,131
Effect of dilutive securities	75		72		68
Weighted-average common shares outstanding - diluted	50,373		50,292		50,199
Basic earnings per share	$	3.94	$	3.88	$	3.86
Diluted earnings per share	$	3.94	$	3.87	$	3.85

9. COMMITMENTS

Purchase Obligations

At December 31, 2016 , Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission rights, and fuel (in thousands of dollars):



	2017		2018		2019		2020		2021		Thereafter
Cogeneration and power production	$	228,545	$	235,366	$	229,450	$	229,473	$	235,922	$	3,150,212
Fuel	56,534		22,070		8,948		8,433		8,399		100,978

As of December 31, 2016 , Idaho Power had 945 MW nameplate capacity of PURPA-related projects on-line, with an additional 178 MW nameplate capacity of projects projected to be on-line in 2017 and an additional 9 MW expected to be added in 2019. The power purchase contracts for these projects have original contract terms ranging from one to 35 years. Idaho Power's expenses associated with PURPA-related projects were approximately $154 million in 2016 , $131 million in 2015 , and $145 million in 2014 .

Idaho Power also has the following long-term commitments for lease guarantees, equipment, maintenance and services, and industry related fees (in thousands of dollars):



	2017		2018		2019		2020		2021		Thereafter
Operating leases	$	3,339	$	4,171	$	4,237	$	4,076	$	4,038	$	29,218
Equipment, maintenance, and service agreements	26,884		12,435		6,185		6,871		3,421		51,085
FERC and other industry-related fees	12,508		12,444		8,434		5,744		5,744		28,720

IDACORP’s expense for operating leases was approximately $4.9 million in 2016 , $4.4 million in 2015 , and $5.9 million in 2014 .

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Guarantees

Through a self-bonding mechanism, Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality, was $71 million at December 31, 2016 , representing IERCo's one-third share of BCC's total reclamation obligation. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2016 , the value of the reclamation trust fund was $78 million . During 2016 , the reclamation trust fund distributed approximately $6 million for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.

IDACORP and Idaho Power enter into financial agreements and power purchase and sale agreements that include indemnification provisions relating to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. IDACORP and Idaho Power periodically evaluate the likelihood of incurring costs under such indemnities based on their historical experience and the evaluation of the specific indemnities. As of December 31, 2016 , management believes the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Neither IDACORP nor Idaho Power has recorded any liability on their respective consolidated balance sheets with respect to these indemnification obligations.

10. CONTINGENCIES

IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, including the items described below. Some of these claims, controversies, disputes, and other contingent matters involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. In such cases, there may be a possible exposure to loss in excess of any amounts accrued. IDACORP and Idaho Power monitor those matters for developments that could affect the likelihood of a loss and the accrued amount, if any, and adjust the amount as appropriate. If the loss contingency at issue is not both probable and reasonably estimable, IDACORP and Idaho Power do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. As of the date of this report, IDACORP's and Idaho Power's accruals for loss contingencies are not material to their financial statements as a whole; however, future accruals could be material in a given period. IDACORP's and Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosures involve significant judgment and may be subject to significant uncertainty.

Western Energy Proceedings

High prices for electricity, energy shortages, and blackouts in California and in the western wholesale markets during 2000 and 2001 caused numerous purchasers of electricity in those markets to initiate proceedings to consider requiring refunds and other forms of disgorgement from energy sellers. Idaho Power and IESCo (as successor to IDACORP Energy L.P.) believe that the current state of the FERC's orders and the settlement releases they have obtained, including a settlement Idaho Power and IESCo executed in December 2016 and approved by the FERC relating to the California energy market proceedings, will eliminate or restrict potential future claims that might result from the remaining proceedings. As IDACORP and Idaho Power believe that their participation in the California and western wholesale market proceedings has effectively concluded, IDACORP and Idaho Power expect that these matters will not have a material adverse effect on their respective results of operations or financial condition in future periods.

Hoku Corporation Bankruptcy Claims

On June 26, 2015, the trustee in the Hoku Corporation chapter 7 bankruptcy case ( In Re: Hoku Corporation , United States Bankruptcy Court, District of Idaho, Case No. 13-40838 JDP) filed a complaint against Idaho Power, alleging that specified

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payments made by Hoku Corporation to Idaho Power in the six years prior to Hoku Corporation's bankruptcy filing in July 2013 should be recoverable by the trustee as constructive fraudulent transfers. Hoku Corporation was the parent entity of Hoku Materials, Inc., with which Idaho Power had an electric service agreement approved by the IPUC in March 2009. Under the electric service agreement, Idaho Power agreed to provide electric service to a polysilicon production facility under construction by Hoku Materials in the state of Idaho. Idaho Power also had agreements with Hoku Materials pertaining to the design and construction of apparatus for the provision of electric service to the polysilicon plant. The trustee's complaint against Idaho Power requested recovery from Idaho Power in amounts up to approximately $36 million. The complaint alleged that the payments made by Hoku Corporation to Idaho Power were subject to recovery by the trustee on the basis that Hoku Corporation was insolvent at the time of the payments and did not have any legal or equitable title in the polysilicon plant or liability for Hoku Materials' debts, and thus did not receive reasonably equivalent value for the payments it made for or on behalf of Hoku Materials. In September 2016, the bankruptcy judge issued an oral opinion granting Idaho Power’s and other parties’ motion for substantive consolidation of Hoku Corporation and Hoku Materials, which consolidated the bankruptcies of Hoku Corporation and Hoku Materials. On December 20, 2016, the bankruptcy judge entered an order of dismissal, with prejudice, of the complaint against Idaho Power, which effectively ended Idaho Power’s participation in the adversary proceedings.

Other Proceedings

IDACORP and Idaho Power are parties to legal claims and legal and regulatory actions and proceedings in the ordinary course of business that are in addition to those discussed above and, as noted above, record an accrual for associated loss contingencies when they are probable and reasonably estimable. As of the date of this report, the companies believe that resolution of those matters will not have a material adverse effect on their respective consolidated financial statements. Idaho Power is also actively monitoring various pending environmental regulations that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to estimate the financial impact of these regulations. However, Idaho Power does believe that future capital investment for infrastructure and modifications to its electric system facilities could be significant to comply with these regulations.

11. BENEFIT PLANS

Idaho Power sponsors defined benefit and other postretirement benefit plans that cover the majority of its employees. Idaho Power also sponsors a defined contribution 401(k) employee savings plan and provides certain post-employment benefits.

Pension Plans

Idaho Power has two pension plans–a noncontributory defined benefit pension plan (pension plan) and two nonqualified defined benefit pension plans for certain senior management employees called the Security Plan for Senior Management Employees I and Security Plan for Senior Management Employees II (together, SMSP). Idaho Power also has a nonqualified defined benefit pension plan for directors that was frozen in 2002. Remaining vested benefits from that plan are included with the SMSP in the disclosures below. The benefits under these plans are based on years of service and the employee's final average earnings.

Idaho Power’s funding policy for the pension plan is to contribute at least the minimum required under the Employee Retirement Income Security Act of 1974 (ERISA) but not more than the maximum amount deductible for income tax purposes. In 2016 , 2015 , and 2014 Idaho Power elected to contribute more than the minimum required amounts in order to bring the pension plan to a more funded position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums.

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The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars):



	Pension Plan						SMSP
	2016			2015			2016			2015

Change in projected benefit obligation:
Benefit obligation at January 1	$	835,523		$	844,812		$	95,389		$	94,410
Service cost	32,019			33,164			1,228			1,689
Interest cost	37,813			35,171			4,275			3,868
Actuarial loss (gain)	22,640			(47,952		)	2,933			(352		)
Plan amendment	81			—			120			—
Benefits paid	(33,016		)	(29,672		)	(4,375		)	(4,226		)
Projected benefit obligation at December 31	895,060			835,523			99,570			95,389
Change in plan assets:
Fair value at January 1	559,616			559,719			—			—
Actual return on plan assets	40,968			(9,431		)	—			—
Employer contributions	40,000			39,000			—			—
Benefits paid	(33,016		)	(29,672		)	—			—
Fair value at December 31	607,568			559,616			—			—
Funded status at end of year	$	(287,492	)	$	(275,907	)	$	(99,570	)	$	(95,389	)
Amounts recognized in the statement of financial position consist of:
Other current liabilities	$	—		$	—		$	(4,733	)	$	(4,423	)
Noncurrent liabilities	(287,492		)	(275,907		)	(94,837		)	(90,966		)
Net amount recognized	$	(287,492	)	$	(275,907	)	$	(99,570	)	$	(95,389	)
Amounts recognized in accumulated other comprehensive income consist of:
Net loss	$	263,634		$	253,212		$	33,660		$	34,260
Prior service cost	96			74			625			673
Subtotal	263,730			253,286			34,285			34,933
Less amount recorded as regulatory asset	(263,730		)	(253,286		)	—			—
Net amount recognized in accumulated other comprehensive income	$	—		$	—		$	34,285		$	34,933
Accumulated benefit obligation	$	766,367		$	714,994		$	91,146		$	86,838

As a non-qualified plan, the SMSP has no plan assets. However, Idaho Power has a Rabbi trust designated to provide funding for SMSP obligations. The Rabbi trust holds investments in marketable securities and corporate-owned life insurance. The recorded value of these investments was approximately $78 million and $69 million at December 31, 2016 and 2015 , respectively, and is reflected in Investments and in Company-owned life insurance on the consolidated balance sheets.

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The following table shows the components of net periodic benefit cost for these plans (in thousands of dollars). For purposes of calculating the expected return on plan assets, the market-related value of assets is equal to the fair value of the assets.



	Pension Plan									SMSP
	2016			2015			2014			2016		2015		2014
Service cost	$	32,019		$	33,164		$	25,292		$	1,228	$	1,689	$	1,645
Interest cost	37,813			35,171			35,415			4,275		3,868		3,856
Expected return on assets	(42,081		)	(42,310		)	(42,289		)	—		—		—
Amortization of net loss	13,331			13,927			3,911			3,532		4,195		2,618
Amortization of prior service cost	59			221			347			168		185		220
Net periodic pension cost	41,141			40,173			22,676			9,203		9,937		8,339
Adjustments due to the effects of regulation ⁽¹⁾	(22,181		)	(21,173		)	12,124			—		—		—
Net periodic benefit cost recognized for financial reporting	$	18,960		$	19,000		$	34,800		$	9,203	$	9,937	$	8,339

⁽¹⁾ Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, income statement recognition of pension plan costs is deferred until costs are recovered through rates.

The following table shows the components of other comprehensive income for the plans (in thousands of dollars):



	Pension Plan									SMSP
	2016			2015			2014			2016			2015			2014
Actuarial (loss) gain during the year	$	(23,753	)	$	(3,790	)	$	(146,674	)	$	(2,933	)	$	353		$	(15,324	)
Reclassification adjustments for:
Amortization of net loss	13,331			13,927			3,911			3,532			4,195			2,618
Plan amendment service cost	(81		)	—			—			(120		)	—			—
Amortization of prior service cost	59			221			347			168			185			220
Adjustment for deferred tax effects	4,083			(4,050		)	55,678			(253		)	(1,851		)	4,881
Adjustment due to the effects of regulation	6,361			(6,308		)	86,738			—			—			—
Other comprehensive income recognized related to pension benefit plans	$	—		$	—		$	—		$	394		$	2,882		$	(7,605	)

In 2017 , IDACORP and Idaho Power expect to recognize as components of net periodic benefit cost $16.6 million from amortizing amounts recorded in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of December 31, 2016 , relating to the pension plan and SMSP. This amount consists of $13.5 million of amortization of net loss for the pension plan and $3.0 million of amortization of net loss and $0.1 million of amortization of prior service cost for the SMSP.

The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):



	2017		2018		2019		2020		2021		2022-2026
Pension Plan	$	32,592	$	34,957	$	37,375	$	39,938	$	42,477	$	248,151
SMSP	4,829		4,630		4,594		5,199		4,843		26,976

As of December 31, 2016 , IDACORP's and Idaho Power's minimum required contributions to the pension plan are estimated to be zero in 2017 , though Idaho Power plans to contribute between $20 million and $40 million to the pension plan during 2017 in order to help balance the regulatory collection of these expenditures with the amount and timing of contributions and to mitigate the cost of being in an underfunded position.

Postretirement Benefits

Idaho Power maintains a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active-employee group plan at the time of retirement as well as their spouses and qualifying dependents. Retirees hired on or after January 1, 1999, have access to the standard medical option at full cost, with no contribution by Idaho Power. Benefits for employees who retire after December 31, 2002, are limited to a fixed amount, which has limited the growth of Idaho Power’s future obligations under this plan.

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The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):



	2016			2015
Change in accumulated benefit obligation:
Benefit obligation at January 1	$	62,393		$	65,999
Service cost	1,116			1,235
Interest cost	2,766			2,678
Actuarial loss (gain)	1,550			(5,008		)
Benefits paid ⁽¹⁾	(3,949		)	(2,511		)
Benefit obligation at December 31	63,876			62,393
Change in plan assets:
Fair value of plan assets at January 1	35,566			38,375
Actual return on plan assets	2,425			85
Employer contributions ⁽¹⁾	957			(383		)
Benefits paid ⁽¹⁾	(3,949		)	(2,511		)
Fair value of plan assets at December 31	34,999			35,566
Funded status at end of year (included in noncurrent liabilities)	$	(28,877	)	$	(26,827	)

⁽¹⁾ Contributions and benefits paid are each net of $3.7 million and $3.5 million of plan participant contributions, and $0.3 million and $0.3 million of Medicare Part D subsidy receipts for 2016 and 2015 , respectively.

Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars):



	2016			2015
Net gain	$	(55	)	$	(1,654	)
Prior service cost	104			130
Subtotal	49			(1,524		)
Less amount recognized in regulatory assets	(49		)	1,524
Net amount recognized in accumulated other comprehensive income	$	—		$	—

The net periodic postretirement benefit cost was as follows (in thousands of dollars):



	2016			2015			2014
Service cost	1,116			$	1,235		$	1,011
Interest cost	2,766			2,678			2,841
Expected return on plan assets	(2,474		)	(2,680		)	(2,595		)
Amortization of prior service cost	26			15			183
Net periodic postretirement benefit cost	$	1,434		$	1,248		$	1,440

The following table shows the components of other comprehensive income for the plan (in thousands of dollars):



	2016			2015			2014
Actuarial (loss) gain during the year	$	(1,600	)	$	2,413		$	(5,733	)
Reclassification adjustments for amortization of prior service cost	26			15			183
Adjustment for deferred tax effects	615			(949		)	2,170
Adjustment due to the effects of regulation	959			(1,479		)	3,380
Other comprehensive income related to postretirement benefit plans	$	—		$	—		$	—

Medicare Act: The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law in December 2003 and established a prescription drug benefit under Medicare Part D, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare’s prescription drug coverage.

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The following table summarizes the expected future benefit payments of the postretirement benefit plan and expected Medicare Part D subsidy receipts (in thousands of dollars):



	2017		2018		2019		2020		2021		2022-2026
Expected benefit payments	$	3,980	$	4,040	$	4,070	$	4,100	$	4,120	$	20,620
Expected Medicare Part D subsidy receipts	370		410		450		480		520		3,240

Plan Assumptions

The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all Idaho Power-sponsored pension and postretirement benefits plans:



	Pension Plan				SMSP				Postretirement Benefits
	2016		2015		2016		2015		2016		2015
Discount rate	4.45	%	4.60	%	4.45	%	4.60	%	4.45	%	4.60	%
Rate of compensation increase ⁽¹⁾	4.11	%	4.11	%	4.75	%	4.50	%	—		—
Medical trend rate	—		—		—		—		8.3	%	9.7	%
Dental trend rate	—		—		—		—		5.0	%	5.0	%
Measurement date	12/31/2016		12/31/2015		12/31/2016		12/31/2015		12/31/2016		12/31/2015

⁽¹⁾ The 2016 rate of compensation increase assumption for the pension plan includes an inflation component of 2.50% plus a 1.61% composite merit increase component that is based on employees' years of service. Merit salary increases are assumed to be 8.0% for employees in their first year of service and scale down to 0% for employees in their fortieth year of service and beyond.

The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho Power-sponsored pension and postretirement benefit plans:



	Pension Plan						SMSP						Postretirement Benefits
	2016		2015		2014		2016		2015		2014		2016		2015		2014
Discount rate	4.60	%	4.25	%	5.20	%	4.60	%	4.20	%	5.10	%	4.60	%	4.20	%	5.15	%
Expected long-term rate of return on assets	7.50	%	7.50	%	7.75	%	—		—		—		7.25	%	7.25	%	7.25	%
Rate of compensation increase	4.11	%	4.11	%	4.30	%	4.50	%	4.50	%	4.50	%	—		—		—
Medical trend rate	—		—		—		—		—		—		8.3	%	9.7	%	6.4	%
Dental trend rate	—		—		—		—		—		—		5.0	%	5.0	%	5.0	%

The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was 8.3 percent in 2016 and is assumed to decrease to 6.8 percent in 2017 , 5.3 percent in 2018, 5.2 percent in 2019 and to gradually decrease to 4.5 percent by 2096 . The assumed dental cost trend rate used to measure the expected cost of dental benefits covered by the plan was 5.0 percent , or equal to the medical trend rate if lower, for all years. A one percentage point change in the assumed health care cost trend rate would have the following effects at December 31, 2016 (in thousands of dollars):



	One-Percentage-Point
	Increase		Decrease
Effect on total of cost components	$	382	$	(280	)
Effect on accumulated postretirement benefit obligation	3,687		(2,841		)

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Plan Assets

Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2016 , for the pension asset portfolio by asset class is set forth below:



Asset Class	Target Allocation		Actual Allocation December 31, 2016
Debt securities	24	%	22	%
Equity securities	54	%	56	%
Real estate	6	%	7	%
Other plan assets	16	%	15	%
Total	100	%	100	%

Assets are rebalanced as necessary to keep the portfolio close to target allocations.

The plan’s principal investment objective is to maximize total return (defined as the sum of realized interest and dividend income and realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio. Emphasis is placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and future payments to pensioners.

The three major goals in Idaho Power’s asset allocation process are to:


•	determine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations;


•	match the cash flow needs of the plan. Idaho Power sets bond allocations sufficient to cover at least five years of benefit payments and cash allocations sufficient to cover the current year benefit payments. Idaho Power then utilizes growth instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; and


•	maintain a prudent risk profile consistent with ERISA fiduciary standards.

Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, core real estate funds, private equity funds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must be readily marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price.

Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA Corporate Bond Index. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current low interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over the past 20 years when interest rates were generally much higher.

Idaho Power’s asset modeling process also utilizes historical market returns to measure the portfolio’s exposure to a “worst-case” market scenario, to determine how much performance could vary from the expected “average” performance over various time periods. This “worst-case” modeling, in addition to cash flow matching and diversification by asset class and investment style, provides the basis for managing the risk associated with investing portfolio assets.

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Fair Value of Plan Assets: Idaho Power classifies its pension plan and postretirement benefit plan investments using the three-level fair value hierarchy described in Note 16. The following table presents the fair value of the plans' investments by asset category (in thousands of dollars).



	Level 1		Level 2		Level 3		Total
Assets at December 31, 2016
Cash and cash equivalents	$	28,632	$	—	$	—	$	28,632
Short-term bonds	11,198		—		—		11,198
Intermediate bonds	11,904		88,734		—		100,638
Long-term bonds	—		20,573		—		20,573
Equity Securities: Large-Cap	80,582		—		—		80,582
Equity Securities: Mid-Cap	68,634		—		—		68,634
Equity Securities: Small-Cap	53,766		—		—		53,766
Equity Securities: Micro-Cap	29,671		—		—		29,671
Equity Securities: International	7,782		—		—		7,782
Equity Securities: Emerging Markets	9,204		—		—		9,204
Plan assets measured at NAV (not subject to hierarchy disclosure)
Equity Securities: International	—		—		—		64,930
Equity Securities: Emerging Markets	—		—		—		24,443
Real estate	—		—		—		41,907
Private market investments	—		—		—		33,713
Commodities fund	—		—		—		31,895
Total	$	301,373	$	109,307	$	—	$	607,568
Postretirement plan assets ⁽¹⁾	$	28	$	34,971	$	—	$	34,999



Assets at December 31, 2015
Cash and cash equivalents	$	10,519	$	—	$	—	$	10,519
Short-term bonds	11,023		—		—		11,023
Intermediate bonds	11,499		92,742		—		104,241
Long-term bonds	—		21,747		—		21,747
Equity Securities: Large-Cap	73,489		—		—		73,489
Equity Securities: Mid-Cap	64,397		—		—		64,397
Equity Securities: Small-Cap	47,777		—		—		47,777
Equity Securities: Micro-Cap	22,186		—		—		22,186
Equity Securities: International	7,698		—		—		7,698
Equity Securities: Emerging Markets	9,679		—		—		9,679
Plan assets measured at NAV (not subject to hierarchy disclosure)
Equity Securities: International	—		—		—		59,787
Equity Securities: Emerging Markets	—		—		—		23,167
Real estate	—		—		—		39,035
Private market investments	—		—		—		37,316
Commodities fund	—		—		—		27,555
Total	$	258,267	$	114,489	$	—	$	559,616
Postretirement plan assets ⁽¹⁾	$	16	$	35,550	$	—	$	35,566

⁽¹⁾ The postretirement benefits assets are primarily life insurance contracts.

For the year ended December 31, 2016 and December 31, 2015 , there were no material transfers into or out of Levels 1, 2, or 3 other than the adoption of ASU 2015-07, Fair Value Measurement (Topic 820) - Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) , which removed from the fair value hierarchy, investments for which the practical expedient is used to measure fair value at net asset value (NAV). In prior years, certain investments were

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measured using NAV as a practical expedient for fair value, and these amounts were included as level 2 and 3 items in the fair value hierarchy. The requirements of this ASU were adopted retrospectively; therefore, the 2015 amounts have been reclassified to conform to the 2016 presentation. Because these amounts are no longer included in the fair value hierarchy as level 3 items, the level 3 reconciliations are no longer applicable and have been excluded from this footnote.

Fair Value Measurement of Level 2 Plan assets and Plan assets measured at NAV:

Level 2 Bonds : These investments represent U.S. government, agency bonds, and corporate bonds. The U.S. government and agency bonds, as well as the corporate bonds, are not traded on an exchange and are valued utilizing market prices for similar assets or liabilities in active markets.

Level 2 Postretirement Asset: This asset represents an investment in a life insurance contract and is recorded at fair value, which is the cash surrender value, less any unpaid expenses. The cash surrender value of this insurance contract is contractually equal to the insurance contract's proportionate share of the market value of an associated investment account held by the insurer. The investments held by the insurer's investment account are all instruments traded on exchanges with readily determinable market prices.

Commingled Funds : These funds, made up of the international, emerging markets equity securities, and commodites fund measured at NAV, are not publicly traded, and therefore no publicly quoted market price is readily available. The value of the commingled funds are presented at estimated fair value, which is determined based on the unit value of the fund. The values of these investments are calculated by the custodian for the fund company on a monthly or more frequent basis, and are based on market prices of the assets held by each of the commingled funds divided by the number of fund shares outstanding for the respective fund. The investments in commingled funds have redemption limitations that permit monthly redemption following notice requirements of 5 to 7 days.

Real Estate : Real estate holdings represent investments in open-ended commingled real estate funds. As the property interests held in these real estate funds are not frequently traded, establishing the market value of the property interests held by the fund, and the resulting unit value of fund shareholders, is based on unobservable inputs including property appraisals by the fund companies, property appraisals by independent appraisal firms, analysis of the replacement cost of the property, discounted cash flows generated by property rents and changes in property values, and comparisons with sale prices of similar properties in similar markets. These open-ended real estate funds also furnish annual audited financial statements that are also used to further validate the information provided. Redemptions are generally available on a quarterly basis, with 10 to 35 days written notice, depending on the individual fund. If the fund has sufficient liquidity, the redemption will be processed at the fund NAV or the fund’s estimate of fair value at the end of the quarter. If the fund does not have sufficient liquidity to honor the full redemption, the remainder will be set for redemption the following quarter on a pro-rata basis with other redemption requests. This same process will repeat until the redemption request has been completed. To protect other fund holders, real estate funds have no duty to liquidate or encumber funds to meet redemption requests.

Private Market Investments : Private market investments represent two categories: fund of hedge funds and venture capital funds. These funds are valued by the fund companies based on the estimated fair values of the underlying fund holdings divided by the fund shares outstanding or multiplied by the ownership percentages of the holder. Some hedge fund strategies utilize securities with readily available market prices, while others utilize less liquid investment vehicles that are valued based on unobservable inputs including cost, operating results, recent funding activity, or comparisons with similar investment vehicles. Redemptions are available on a quarterly basis with 70 days written notice. Redemptions will be processed at the quarterly NAV or fair value within 60 days following quarter end. In the event of a full redemption, a reserve amount of 5% to 10% of the redemption amount may be held in reserve until the audited financial statements of the fund are published. This allows the fund to adjust the redemption so that other fund holders are not adversely impacted. Venture capital fund investments are valued by the fund companies based on estimated fair value of the underlying fund holdings divided by the fund shares outstanding. Some venture capital investments have progressed to the point that they have readily available exchange-based market valuations. Early stage venture investments are valued based on unobservable inputs including cost, operating results, discounted cash flows, the price of recent funding events, or pending offers from other viable entities. These private market investments furnish annual audited financial statements that are also used to further validate the information provided. These funds are formed for a stated life of 10 to 15 years. The general partner can extend the fund life for 2 or 3 one-year periods. The fund can be further extended with the approval of the limited partners. There are generally no redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer.

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Employee Savings Plan

Idaho Power has a defined contribution plan designed to comply with Section 401(k) of the Internal Revenue Code and that covers substantially all employees. Idaho Power matches specified percentages of employee contributions to the plan. Matching annual contributions were $8 million , $7 million , and $7 million in 2016 , 2015 , and 2014 , respectively.

Post-employment Benefits

Idaho Power provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement, in addition to the health care benefits required under the Consolidated Omnibus Budget Reconciliation Act. These benefits include salary continuation, health care and life insurance for those employees found to be disabled under Idaho Power’s disability plans, and health care for surviving spouses and dependents. Idaho Power accrues a liability for such benefits. The post employment benefit amounts included in other deferred credits on IDACORP’s and Idaho Power’s consolidated balance sheets at both December 31, 2016 and 2015 , were $2 million .

12. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS

The following table presents the major classifications of Idaho Power’s utility plant in service, annual depreciation provisions as a percent of average depreciable balance, and accumulated provision for depreciation for the years ended December 31, 2016 and 2015 (in thousands of dollars):



	2016					2015
	Balance			Avg Rate		Balance			Avg Rate
Production	$	2,551,823		2.40	%	$	2,422,175		2.46	%
Transmission	1,120,903			2.02	%	1,077,065			2.01	%
Distribution	1,637,131			2.72	%	1,578,445			2.72	%
General and Other	422,187			5.49	%	407,779			5.62	%
Total in service	5,732,044			2.64	%	5,485,464			2.68	%
Accumulated provision for depreciation	(1,988,477		)			(1,913,927		)
In service - net	$	3,743,567				$	3,571,537

At December 31, 2016 , Idaho Power's construction work in progress balance of $405 million included relicensing costs of $249 million for the Hells Canyon Complex (HCC), Idaho Power's largest hydroelectric complex. The IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $6.5 million annually ( $10.7 million when grossed-up for the effect of income taxes) of AFUDC relating to the HCC relicensing project. Collecting these amounts now will reduce the amount collected in the future once the HCC relicensing costs are approved for recovery in base rates. At December 31, 2016 , Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $103 million .

Idaho Power's ownership interest in three jointly-owned generating facilities is included in the table above. Under the joint operating agreements for these facilities, each participating utility is responsible for financing its share of construction, operating, and leasing costs. Idaho Power's proportionate share of operating expenses for each facility is included in the Consolidated Statements of Income. These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power’s participation, were as follows at December 31, 2016 (in thousands of dollars):



Name of Plant	Location	Utility Plant in Service		Construction Work in Progress		Accumulated Provision for Depreciation		Ownership %	MW ⁽¹⁾
Jim Bridger Units 1-4	Rock Springs, WY	$	710,910	$	5,972	$	302,291	33	771
Boardman	Boardman, OR	82,419		34		67,568		10	64
Valmy Units 1 and 2	Winnemucca, NV	410,390		1,373		189,557		50	284

⁽¹⁾ Idaho Power’s share of nameplate capacity.

IERCo, Idaho Power’s wholly-owned subsidiary, is a joint venturer in BCC. Idaho Power’s coal purchases from the joint venture were $93 million in 2016 , $93 million in 2015 , and $79 million in 2014 .

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Idaho Power has contracts to purchase the energy from four PURPA qualified facilities that are 50 percent owned by Ida-West. Idaho Power’s power purchases from these facilities were $8 million in 2016 , $8 million in 2015 , and $9 million in 2014 .

IDACORP's consolidated VIE, Marysville, owns a hydroelectric plant with a net book value of approximately $16 million and $19 million at December 31, 2016 and 2015 , respectively.

13. ASSET RETIREMENT OBLIGATIONS (ARO)

The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of property, plant, and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. Under the guidance, when a liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its estimated settlement value and paid, and the capitalized cost is depreciated over the useful life of the related asset. If, at the end of the asset’s life, the recorded liability differs from the actual obligations paid, a gain or loss would be recognized. As a rate-regulated entity, Idaho Power records regulatory assets or liabilities instead of accretion, depreciation, and gains or losses, as approved by the IPUC. The regulatory assets recorded under this order do not earn a return on investment. Beginning June 1, 2012, accretion, depreciation, and gains or losses related to the Boardman generating facility have been exempted from such regulatory treatment as Idaho Power is now collecting amounts related to the decommissioning of Boardman in rates.

Idaho Power’s recorded AROs relate to the removal of polychlorinated biphenyl-contaminated equipment at its distribution facilities and the reclamation and removal costs at its jointly-owned coal-fired generation facilities. In 2016 , changes in estimates at the coal-fired generation facilities resulted in a net increase of $1.8 million in the recorded AROs.

Idaho Power also has additional AROs associated with its transmission system, hydroelectric facilities, natural gas-fired generation facilities, and jointly owned coal-fired generation facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the consolidated financial statements.

The regulated operations of Idaho Power also collect removal costs in rates for certain assets that do not have associated AROs. Idaho Power is required to redesignate these removal costs as regulatory liabilities. See Note 3 for the removal costs recorded as regulatory liabilities on IDACORP’s and Idaho Power’s consolidated balance sheets as of December 31, 2016 and 2015 .

The following table presents the changes in the carrying amount of AROs (in thousands of dollars):



	2016			2015
Balance at beginning of year	$	26,153		$	21,930
Accretion expense	1,031			993
Revisions in estimated cash flows	1,759			5,043
Liability settled	(2,686		)	(1,813		)
Balance at end of year	$	26,257		$	26,153

14. INVESTMENTS

The table below summarizes IDACORP’s and Idaho Power’s investments as of December 31 (in thousands of dollars):



	2016		2015
Idaho Power investments:
Bridger Coal Company (equity method investment)	$	82,299	$	95,159
Exchange traded short-term bond funds and cash equivalents	23,908		24,459
Executive deferred compensation plan investments	111		102
Total Idaho Power investments	106,318		119,720
Investments in affordable housing (IDACORP Financial Services)	7,643		9,909
Ida-West joint ventures (equity method investments)	11,213		11,123
Total IDACORP investments	$	125,174	$	140,752

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Equity Method Investments

Idaho Power, through its subsidiary IERCo, is a 33 percent owner of BCC. Ida-West, through separate subsidiaries, owns 50 percent of three electric generation projects that are accounted for using the equity method: South Forks Joint Venture, Hazelton/Wilson Joint Venture, and Snow Mountain Hydro LLC. All projects are reviewed periodically for impairment. The table below presents IDACORP’s and Idaho Power’s earnings (loss) of unconsolidated equity-method investments (in thousands of dollars):



	2016		2015		2014
Bridger Coal Company (Idaho Power)	$	10,855	$	9,773	$	10,814
Ida-West joint ventures	2,016		1,355		1,614
Other	—		—		(56		)
Total	$	12,871	$	11,128	$	12,372

Investments in Equity Securities

Investments in securities classified as available-for-sale securities are reported at fair value. Any unrealized gains or losses on available-for-sale securities are included in income, as the fair value option has been elected for these instruments. Unrealized gains and losses on available-for-sale securities were immaterial at December 31, 2016 and December 31, 2015 . The following table summarizes sales of available-for-sale securities (in thousands of dollars):



	2016		2015		2014
Proceeds from sales	$	15,693	$	34,243	$	—
Gross realized gains from sales	54		—		—
Gross realized losses from sales	—		—		—

At the end of each reporting period, IDACORP and Idaho Power analyze securities in loss positions to determine whether they have experienced a decline in market value that is considered other-than-temporary. At December 31, 2016 and December 31, 2015 , there were no indicators of other-than-temporary impairment related to IDACORP's and Idaho Power's investments.

Investments in Affordable Housing

IFS invests primarily in affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS 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.

15. DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Price Risk

Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk may be influenced by market participants’ nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop.

All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and sales, though none of these instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default. Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and

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payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table below.

The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2016 , 2015 , and 2014 (in thousands of dollars):



	Location of Realized Gain/(Loss) on Derivatives Recognized in Income	Gain/(Loss) on Derivatives Recognized in Income ⁽¹⁾
		2016			2015			2014
Financial swaps	Off-system sales	$	1,405		$	2,882		$	(4,119	)
Financial swaps	Purchased power	586			748			(1,416		)
Financial swaps	Fuel expense	(1,947		)	(6,045		)	3,862
Financial swaps	Other operations and maintenance	(161		)	(50		)	(158		)
Forward contracts	Off-system sales	—			—			277
Forward contracts	Purchased power	31			(6		)	(279		)
Forward contracts	Fuel expense	139			54			94

⁽¹⁾ Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.

Settlement gains and losses on electricity swap contracts are recorded on the income statement in off-system sales or purchased power depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are recorded in other operations and maintenance expense. See Note 16 for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.

Derivative Instrument Summary

The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets and reconciles the gross amounts of derivatives recognized as assets and as liabilities to the net amounts presented in the balance sheets at December 31, 2016 and 2015 (in thousands of dollars):



		Asset Derivatives								Liability Derivatives
	Balance Sheet Location	Gross Fair Value		Amounts Offset				Net Assets		Gross Fair Value		Amounts Offset			Net Liabilities
	Balance Sheet Location	Gross Fair Value		Amounts Offset				Net Assets		Gross Fair Value		Amounts Offset			Net Liabilities
December 31, 2016
Current:
Financial swaps	Other current assets	$	8,134	$	(2,183	)	⁽¹⁾	$	5,951	$	302	$	(302	)	$	—
Total		$	8,134	$	(2,183	)		$	5,951	$	302	$	(302	)	$	—

December 31, 2015
Current:
Financial swaps	Other current assets	$	999	$	(785	)		$	214	$	785	$	(785	)	$	—
Financial swaps	Other current liabilities	177		(177		)		—		5,146		(177		)	4,969
Forward contracts	Other current assets	64		—				64		—		—			—
Forward contracts	Other current liabilities	—		—				—		3		—			3
Long-term:
Financial swaps	Other assets	148		(22		)		126		22		(22		)	—
Total		$	1,388	$	(984	)		$	404	$	5,956	$	(984	)	$	4,972

⁽¹⁾ Current asset derivative amounts offset include $1.9 million of collateral payable for the period ending December 31, 2016 .

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The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2016 and 2015 (in thousands of units):



		December 31,
Commodity	Units	2016	2015
Electricity purchases	MWh	217	357
Electricity sales	MWh	135	120
Natural gas purchases	MMBtu	6,604	11,597
Natural gas sales	MMBtu	70	78
Diesel purchases	Gallons	1,188	1,068

Credit Risk

At December 31, 2016 , Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary. Idaho Power’s physical power contracts are commonly under Western Systems Power Pool agreements, physical gas contracts are usually under North American Energy Standards Board contracts, and financial transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.

Credit-Contingent Features

Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at December 31, 2016 , was $0.3 million . Idaho Power posted no cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2016 , Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $2.7 million to cover open liability positions as well as completed transactions that have not yet been paid.

16. FAIR VALUE MEASUREMENTS

IDACORP and Idaho Power have categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.

Financial assets and liabilities recorded on the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:

• Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that IDACORP and Idaho Power have the ability to access.

• Level 2: Financial assets and liabilities whose values are based on the following:

a) quoted prices for similar assets or liabilities in active markets;

b) quoted prices for identical or similar assets or liabilities in non-active markets;

c) pricing models whose inputs are observable for substantially the full term of the asset or liability; and

d) pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term of the asset or liability.

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IDACORP and Idaho Power Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable market data.

• Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

IDACORP’s and Idaho Power’s assessment of a particular input's significance to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. An item recorded at fair value is reclassified among levels when changes in the nature of valuation inputs cause the item to no longer meet the criteria for the level in which it was previously categorized. There were no transfers between levels or material changes in valuation techniques or inputs during the years ended December 31, 2016 and 2015 .

The following table presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2016 and 2015 (in thousands of dollars):



	December 31, 2016								December 31, 2015
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Money market funds
IDACORP	$	15,000	$	—	$	—	$	15,000	$	1,000	$	—	$	—	$	1,000
Idaho Power	29,967		—		—		29,967		10,000		—		—		10,000
Derivatives	5,951		—		—		5,951		340		64		—		404
Trading securities: Equity securities	111		—		—		111		102		—		—		102
Available-for-sale securities: Equity securities	23,908		—		—		23,908		24,459		—		—		24,459
Liabilities:
Derivatives	$	—	$	—	$	—	$	—	$	286	$	4,686	$	—	$	4,972

Idaho Power’s derivatives are contracts entered into as part of its management of loads and resources. Electricity derivatives are valued on the Intercontinental Exchange (ICE) with quoted prices in an active market. Natural gas and diesel derivative valuations are performed using New York Mercantile Exchange (NYMEX) and ICE pricing, adjusted for location basis, which are also quoted under NYMEX and ICE pricing. Trading securities consist of employee-directed investments held in a Rabbi trust and are related to an executive deferred compensation plan. Available-for-sale securities are related to the SMSP, are held in a Rabbi trust, and are actively traded money market and exchange-traded funds with quoted prices in active markets.

The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of December 31, 2016 and 2015 , using available market information and appropriate valuation methodologies (in thousands of dollars):



	December 31, 2016				December 31, 2015
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(thousands of dollars)
IDACORP
Assets:
Notes receivable ⁽¹⁾	$	3,804	$	3,804	$	3,804	$	3,804
Liabilities:
Long-term debt ⁽¹⁾	1,745,678		1,858,666		1,726,474		1,813,243
Idaho Power
Liabilities:
Long-term debt ⁽¹⁾	$	1,745,678	$	1,858,666	$	1,726,474	$	1,813,243

⁽¹⁾ Notes receivable and long-term debt are categorized as Level 3 and Level 2, respectively, of the fair value hierarchy, as defined earlier in this Note 16.

Notes receivable are related to Ida-West and are valued based on unobservable inputs, including discounted cash flows, which are partially based on forecasted hydroelectric conditions. Long-term debt is not traded on an exchange and is valued using

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quoted rates for similar debt in active markets. Carrying values for cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued approximate fair value.

17. SEGMENT INFORMATION

IDACORP’s only reportable segment is utility operations. The utility operations segment’s primary source of revenue is the regulated operations of Idaho Power. Idaho Power’s regulated operations include the generation, transmission, distribution, purchase, and sale of electricity. This segment also includes income from IERCo, a wholly-owned subsidiary of Idaho Power that is also subject to regulation and is a one-third owner of BCC, an unconsolidated joint venture.

IDACORP’s other operating segments are below the quantitative and qualitative thresholds for reportable segments and are included in the “All Other” category in the table below. This category is comprised of IFS’s investments in affordable housing developments and historic rehabilitation projects, Ida-West’s joint venture investments in small hydroelectric generation projects, the remaining activities of IESCo, the successor to which wound down its energy marketing operations in 2003, and IDACORP’s holding company expenses.

The table below summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands of dollars):



	Utility Operations		All Other			Eliminations			Consolidated Total
2016
Revenues	$	1,259,353	$	2,667		$	—		$	1,262,020
Operating income	265,491		6,285			—			271,776
Other income	27,658		6			—			27,664
Interest income	4,235		127			(121		)	4,241
Equity-method income	10,855		2,016			—			12,871
Interest expense	81,812		344			(121		)	82,035
Income before income taxes	226,427		8,090			—			234,517
Income tax expense (benefit)	37,185		(756		)	—			36,429
Income attributable to IDACORP, Inc.	189,242		9,046			—			198,288
Total assets	6,236,744		73,137			(19,984		)	6,289,897
Expenditures for long-lived assets	296,948		2			—			296,950

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2015
Revenues	$	1,267,505	$	2,784		$	—		$	1,270,289
Operating income	282,252		(155		)	—			282,097
Other income	25,868		37			—			25,905
Interest income	3,037		64			(62		)	3,039
Equity-method income	9,773		1,355			—			11,128
Interest expense	81,718		278			(62		)	81,934
Income before income taxes	239,211		1,024			—			240,235
Income tax expense (benefit)	48,228		(2,468		)	—			45,760
Income attributable to IDACORP, Inc.	190,983		3,696			—			194,679
Total assets	5,968,835		71,704			(17,225		)	6,023,314
Expenditures for long-lived assets	293,969		52			—			294,021

2014
Revenues	$	1,278,651	$	3,873		$	—		$	1,282,524
Operating income	253,437		259			—			253,696
Other income	21,517		37			—			21,554
Interest income	2,705		34			(34		)	2,705
Equity-method income	10,814		1,558			—			12,372
Interest expense	79,570		265			(34		)	79,801
Income before income taxes	208,903		1,623			—			210,526
Income tax expense (benefit)	19,516		(2,744		)	—			16,772
Income attributable to IDACORP, Inc.	189,387		4,093			—			193,480
Total assets	5,604,506		109,044			(12,513		)	5,701,037
Expenditures for long-lived assets	273,911		183			—			274,094

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18. OTHER INCOME AND EXPENSE

The following table presents the components of IDACORP’s Other income, net and Idaho Power's Other (expense) income, net (in thousands of dollars):



IDACORP - Other income, net	2016			2015			2014
Investment income, net	$	4,466		$	2,890		$	2,655
Carrying charges on regulatory assets	2,082			1,774			1,949
Other income	767			777			588
Life insurance proceeds, net of premiums	2,588			1,739			1,164
Other expense	(29		)	(21		)	(28		)
Total	$	9,874		$	7,159		$	6,328
Idaho Power - Other expense, net
Investment income, net	$	4,460		$	2,889		$	2,655
Carrying charges on regulatory assets	2,082			1,774			1,949
Other income	761			739			551
SMSP expense	(9,203		)	(9,937		)	(8,339		)
Life insurance proceeds, net of premiums	2,588			1,739			1,164
Other expense	(2,632		)	(2,275		)	(2,343		)
Total	$	(1,944	)	$	(5,071	)	$	(4,363	)

19. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

Comprehensive income includes net income and amounts related to the SMSP. The table below presents changes in components of accumulated other comprehensive income (AOCI), net of tax, during the years ended December 31, 2016 , 2015 , and 2014 (in thousands of dollars). Items in parentheses indicate reductions to AOCI.



	Year Ended December 31,
	2016			2015			2014
Defined benefit pension items
Balance at beginning of period	$	(21,276	)	$	(24,158	)	$	(16,553	)
Other comprehensive income before reclassifications	(1,859		)	214			(9,333		)
Amounts reclassified out of AOCI	2,253			2,668			1,728
Net current-period other comprehensive income	394			2,882			(7,605		)
Balance at end of period	$	(20,882	)	$	(21,276	)	$	(24,158	)

The table below presents amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the years ended December 31, 2016 , 2015 , and 2014 (in thousands of dollars). Items in parentheses indicate increases to net income.



	Amount Reclassified from AOCI
	Year Ended December 31,
	2016			2015			2014
Amortization of defined benefit pension items ⁽¹⁾
Prior service cost	$	168		$	185		$	220
Net loss	3,532			4,195			2,618
Total before tax	3,700			4,380			2,838
Tax benefit ⁽²⁾	(1,447		)	(1,712		)	(1,110		)
Net of tax	2,253			2,668			1,728
Total reclassification for the period	$	2,253		$	2,668		$	1,728

⁽¹⁾ Amortization of these items is included in IDACORP's consolidated income statements in other operating expenses and in Idaho Power's consolidated income statements in other expense, net.

⁽²⁾ The tax benefit is included in income tax expense in the consolidated income statements of both IDACORP and Idaho Power.

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20. RELATED PARTY TRANSACTIONS

IDACORP: Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and its subsidiaries. Idaho Power charges IDACORP for the costs of these services based on service agreements and other specifically identified costs. For these services, Idaho Power billed IDACORP $0.8 million in 2016 , $0.9 million in 2015 , and $1.4 million in 2014 .

Ida-West: Idaho Power purchases all of the power generated by four of Ida-West’s hydroelectric projects located in Idaho. Idaho Power paid Ida-West $8 million in 2016 and 2015 and $9 million in 2014.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

IDACORP, Inc.

Boise, Idaho

We have audited the accompanying consolidated balance sheets of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, 2016 and 2015 , and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2016 . Our audits also included the financial statement schedules listed in the Index at Item 8. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of IDACORP, Inc. and subsidiaries at December 31, 2016 and 2015 , and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 , in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2016 , based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2017 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

February 23, 2017

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Idaho Power Company

Boise, Idaho

We have audited the accompanying consolidated balance sheets of Idaho Power Company and subsidiary (the “Company”) as of December 31, 2016 and 2015 , and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2016 . Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Idaho Power Company and subsidiary at December 31, 2016 and 2015 , and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 , in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

February 23, 2017

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SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED

QUARTERLY FINANCIAL DATA

The following unaudited information is presented for each quarter of 2016 and 2015 (in thousands of dollars, except for per share amounts). In the opinion of each company, all adjustments necessary for a fair statement of such amounts for such periods have been included. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year. Accordingly, earnings information for any three-month period should not be considered as a basis for estimating operating results for a full fiscal year. Amounts are based upon quarterly statements and the sum of the quarters may not equal the annual amount reported.



	Quarter Ended
	March 31		June 30		September 30		December 31
IDACORP, Inc.
2016
Revenues	$	280,956	$	315,436	$	372,045	$	293,583
Operating income	43,818		76,953		97,928		53,077
Net income	25,530		56,386		83,017		33,155
Net income attributable to IDACORP, Inc.	25,729		56,246		83,100		33,213
Basic earnings per share	$	0.51	$	1.12	$	1.65	$	0.66
Diluted earnings per share	$	0.51	$	1.12	$	1.65	$	0.66
2015
Revenues	$	279,395	$	336,328	$	369,165	$	285,401
Operating income	42,904		85,976		104,664		48,552
Net income	23,344		66,190		73,267		31,673
Net income attributable to IDACORP, Inc.	23,430		66,080		73,336		31,832
Basic earnings per share	$	0.47	$	1.32	$	1.46	$	0.63
Diluted earnings per share	$	0.47	$	1.31	$	1.46	$	0.63
Idaho Power Company
2016
Revenues	$	280,566	$	314,411	$	371,474	$	292,902
Income from operations	47,124		79,409		100,928		49,836
Net income	25,534		54,807		80,029		28,872
2015
Revenues	$	278,774	$	335,321	$	368,517	$	284,893
Income from operations	46,159		88,836		107,614		51,833
Net income	23,462		64,340		71,727		31,455

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures - IDACORP, Inc.

The Chief Executive Officer and Chief Financial Officer of IDACORP, Inc., based on their evaluation of IDACORP, Inc.’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2016 , have concluded that IDACORP, Inc.’s disclosure controls and procedures are effective as of that date.

Internal Control Over Financial Reporting - IDACORP, Inc.

Management’s Annual Report on Internal Control Over Financial Reporting

The management of IDACORP is responsible for establishing and maintaining adequate internal control over financial reporting for IDACORP. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:


•	pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;


•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and


•	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

IDACORP’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2016 . In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013) .

Based on its assessment, management concluded that, as of December 31, 2016 , IDACORP’s internal control over financial reporting is effective based on those criteria.

IDACORP’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2016 and issued a report, which appears on the next page and expresses an unqualified opinion on the effectiveness of IDACORP’s internal control over financial reporting as of December 31, 2016 .

February 23, 2017

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

IDACORP, Inc.

Boise, Idaho

We have audited the internal control over financial reporting of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, 2016 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting . Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016 , based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2016 of the Company and our report dated February 23, 2017 expressed an unqualified opinion on those financial statements and financial statement schedules.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

February 23, 2017

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Disclosure Controls and Procedures - Idaho Power Company

The Chief Executive Officer and Chief Financial Officer of Idaho Power Company, based on their evaluation of Idaho Power Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2016 , have concluded that Idaho Power Company's disclosure controls and procedures are effective as of that date.

Internal Control Over Financial Reporting - Idaho Power Company

Management’s Annual Report on Internal Control Over Financial Reporting

The management of Idaho Power Company (Idaho Power) is responsible for establishing and maintaining adequate internal control over financial reporting of Idaho Power. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:


•	pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;


•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and


•	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Idaho Power’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2016 . In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013) .

Based on its assessment, management concluded that, as of December 31, 2016 , Idaho Power’s internal control over financial reporting is effective based on those criteria.

Idaho Power’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2016 and issued a report which appears on the next page and expresses an unqualified opinion on the effectiveness of Idaho Power’s internal control over financial reporting as of December 31, 2016 .

February 23, 2017

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Idaho Power Company

Boise, Idaho

We have audited the internal control over financial reporting of Idaho Power Company and subsidiary (the “Company”) as of December 31, 2016 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting . Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2016 of the Company and our report dated February 23, 2017 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

February 23, 2017

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Changes in Internal Control Over Financial Reporting - IDACORP, Inc. and Idaho Power Company

There have been no changes in IDACORP, Inc.’s or Idaho Power Company’s internal control over financial reporting during the quarter ended December 31, 2016 that have materially affected, or are reasonably likely to materially affect, IDACORP, Inc.’s or Idaho Power Company’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

The portions of IDACORP’s definitive proxy statement appearing under the captions “Proposal No. 1: Election of Directors,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “Board of Directors - Committees of the Board of Directors - Audit Committee,” “Corporate Governance at IDACORP - Codes of Business Conduct,” and "Corporate Governance at IDACORP - Certain Relationships and Related Transactions" to be filed pursuant to Regulation 14A for the 2017 annual meeting of shareholders are hereby incorporated by reference.

Information regarding IDACORP’s executive officers required by this item appears in Item 1 of this report under “Executive Officers of the Registrants.”

ITEM 11. EXECUTIVE COMPENSATION

The portion of IDACORP’s definitive proxy statement appearing under the caption “Executive Compensation” to be filed pursuant to Regulation 14A for the 2017 annual meeting of shareholders is hereby incorporated by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The portion of IDACORP’s definitive proxy statement appearing under the caption “Security Ownership of Directors, Executive Officers, and Five-Percent Shareholders” to be filed pursuant to Regulation 14A for the 2017 annual meeting of shareholders is hereby incorporated by reference. The table below includes information as of December 31, 2016 , with respect to equity compensation plans where equity securities of IDACORP may be issued. These plans are the 1994 Restricted Stock Plan (RSP), which was terminated on February 9, 2017, and the IDACORP 2000 Long-Term Incentive and Compensation Plan (LTICP).

Equity Compensation Plan Information



Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights	(b) Weighted-average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by shareholders ⁽¹⁾	—	$	—	950,577	⁽²⁾
Equity compensation plans not approved by shareholders	—	$	—	—
Total	—	$	—	950,577

⁽¹⁾ Consists of the RSP (terminated as of February 9, 2017) and the LTICP.
⁽²⁾ 934,781 shares under the LTICP may be issued in connection with stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares, or other equity-based awards as of December 31, 2016. As of December 31, 2016, 15,796 shares remained available for future issuance under the RSP prior to termination of the plan. The number of shares listed in this column excludes (i) issued but unvested performance-based restricted shares, and (ii) issued but unvested time-based restricted shares, in both cases issued pursuant to the LTICP and unvested as of December 31, 2016.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The portions of IDACORP’s definitive proxy statement appearing under the captions “Certain Relationships and Related Transactions” and “Corporate Governance at IDACORP – Director Independence and Executive Sessions” to be filed pursuant to Regulation 14A for the 2017 annual meeting of shareholders are hereby incorporated by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

IDACORP: The portion of IDACORP’s definitive proxy statement appearing under the caption “Independent Accountant Billings” in the proxy statement to be filed pursuant to Regulation 14A for the 2017 annual meeting of shareholders is hereby incorporated by reference.

Idaho Power: The table below presents the aggregate fees our principal independent registered public accounting firm, Deloitte & Touche LLP, billed or is expected to bill to Idaho Power for the fiscal years ended December 31, 2016 and 2015 :



	2016		2015
Audit fees	$	1,344,108	$	1,280,500
Audit-related fees ⁽¹⁾	25,000		6,732
Tax fees ⁽²⁾	4,117		37,655
All other fees ⁽³⁾	2,000		2,000
Total	$	1,375,225	$	1,326,887

⁽¹⁾ Includes agreed-upon procedures in connection with Bonneville Power Administration's evaluation of Idaho Power's compliance with its Residential Exchange Program.
⁽²⁾ Includes fees for benefit plan tax returns and consultation related to tax planning.
⁽³⁾ Accounting research tool subscription.

Policy on Audit Committee Pre-Approval:

Idaho Power and the Audit Committee are committed to ensuring the independence of the independent registered public accounting firm, both in fact and in appearance. In this regard, the Audit Committee has established and periodically reviews a pre-approval policy for audit and non-audit services. For 2016 and 2015 , all audit and non-audit services and all fees paid in connection with those services were pre-approved by the Audit Committee.

In addition to the audits of Idaho Power’s consolidated financial statements, the independent public accounting firm may be engaged to provide certain audit-related, tax, and other services. The Audit Committee must pre-approve all services performed by the independent public accounting firm to assure that the provision of those services does not impair the public accounting firm’s independence. The services that the Audit Committee will consider include: audit services such as attest services, changes in the scope of the audit of the financial statements, and the issuance of comfort letters and consents in connection with financings; audit-related services such as internal control reviews and assistance with internal control reporting requirements; attest services related to financial reporting that are not required by statute or regulation, and accounting consultations and audits related to proposed transactions and new or proposed accounting rules, standards and interpretations; and tax compliance and planning services. Unless a type of service to be provided by the independent public accounting firm has received general pre-approval, it will require specific pre-approval by the Audit Committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by the Audit Committee. Under the pre-approval policy, the Audit Committee has delegated to the Chairman of the Audit Committee pre-approval authority for proposed services; however, the Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting.

Any request to engage the independent public accounting firm to provide a service which has not received general pre-approval must be submitted as a written proposal to Idaho Power’s Chief Financial Officer with a copy to the General Counsel. The request must include a detailed description of the service to be provided, the proposed fee, and the business reasons for engaging the independent public accounting firm to provide the service. Upon approval by the Chief Financial Officer, the General Counsel, and the independent public accounting firm that the proposed engagement complies with the terms of the pre-approval policy and the applicable rules and regulations, the request will be presented to the Audit Committee or the Committee Chairman, as the case may be, for pre-approval.

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In determining whether to pre-approve the engagement of the independent public accounting firm, the Audit Committee or the Committee Chairman, as the case may be, must consider, among other things, the pre-approval policy, applicable rules and regulations, and whether the nature of the engagement and the related fees are consistent with the following principles:

• the independent public accounting firm cannot function in the role of management of Idaho Power; and

• the independent public accounting firm cannot audit its own work.

The pre-approval policy and separate supplements to the pre-approval policy describe the specific audit, audit related, tax, and other services that have the general pre-approval of the Audit Committee. The term of any pre-approval is 12 months from the date of pre-approval, unless the Audit Committee specifically provides for a different period. The Audit Committee will periodically revise the list of pre-approved services, based on subsequent determinations.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(1) and (2) Please refer to Part II, Item 8 - “Financial Statements and Supplementary Data” for a complete listing of consolidated financial statements and financial statement schedules.

(3) Exhibits . Note Regarding Reliance on Statements in Agreements : The agreements filed as exhibits to this Annual Report on Form 10-K are filed to provide information regarding their terms and are not intended to provide any other factual or disclosure information about IDACORP, Inc., Idaho Power Company, or the other parties to the agreements. Some of the agreements contain statements, representations, and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and (a) should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate; (b) have been qualified by disclosures that were made to the other party, which disclosures are not necessarily reflected in the agreement; (c) may apply standards of materiality in a way that is different from what may be viewed as material to investors; and (d) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. Accordingly, readers should not rely upon the statements, representations, or warranties made in the agreements.



		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith
2	Agreement and Plan of Exchange between IDACORP, Inc. and Idaho Power Company, dated as of February 2, 1998	S-4	333-48031	A	3/16/1998
3.1	Restated Articles of Incorporation of Idaho Power Company as filed with the Secretary of State of Idaho on June 30, 1989	S-3 Post-Effective Amend. No. 2	33-00440	4(a)(xiii)	6/30/1989
3.2	Statement of Resolution Establishing Terms of Flexible Auction Series A, Serial Preferred Stock, Without Par Value (cumulative stated value of $100,000 per share) of Idaho Power Company, as filed with the Secretary of State of Idaho on November 5, 1991	S-3	33-65720	4(a)(ii)	7/7/1993
3.3	Statement of Resolution Establishing Terms of 7.07% Serial Preferred Stock, Without Par Value (cumulative stated value of $100 per share) of Idaho Power Company, as filed with the Secretary of State of Idaho on June 30, 1993	S-3	33-65720	4(a)(iii)	7/7/1993
3.4	Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998	S-8 Post-Effective Amend. No. 1	33-56071-99	3(d)	10/1/1998
3.5	Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with the Secretary of State of Idaho on June 15, 2000	10-Q	1-3198	3(a)(iii)	8/4/2000
3.6	Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with the Secretary of State of Idaho on January 21, 2005	8-K	1-3198	3.3	1/26/2005
3.7	Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as amended, as filed with the Secretary of State of Idaho on November 19, 2007	8-K	1-3198	3.3	11/19/2007

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		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith
3.8	Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as amended, as filed with the Secretary of State of Idaho on May 18, 2012	8-K	1-3198	3.14	5/21/2012
3.9	Amended Bylaws of Idaho Power Company, amended on November 15, 2007 and presently in effect	8-K	1-3198	3.2	11/19/2007
3.10	Articles of Incorporation of IDACORP, Inc.	S-3	333-64737	3.1	11/4/1998
3.11	Articles of Amendment to Articles of Incorporation of IDACORP, Inc. as filed with the Secretary of State of Idaho on March 9, 1998	S-3 Amend. No. 1	333-64737	3.2	11/4/1998
3.12	Articles of Amendment to Articles of Incorporation of IDACORP, Inc. creating A Series Preferred Stock, without par value, as filed with the Secretary of State of Idaho on September 17, 1998	S-3 Post-Effective Amend. No. 1	333-00139-99	3(b)	9/22/1998
3.13	Articles of Amendment to Articles of Incorporation of IDACORP, Inc., as amended, as filed with the Secretary of State of Idaho on May 18, 2012	8-K	1-14465	3.13	5/21/2012
3.14	Amended and Restated Bylaws of IDACORP, Inc., amended on October 29, 2014 and presently in effect	10-Q	1-14465	3.15	10/30/2014
4.1	Mortgage and Deed of Trust, dated as of October 1, 1937, between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) and R. G. Page, as Trustees		2-3413	B-2
4.2	Idaho Power Company Supplemental Indentures to Mortgage and Deed of Trust:
	File number 1-MD, as Exhibit B-2-a, First, July 1, 1939
	File number 2-5395, as Exhibit 7-a-3, Second, November 15, 1943
	File number 2-7237, as Exhibit 7-a-4, Third, February 1, 1947
	File number 2-7502, as Exhibit 7-a-5, Fourth, May 1, 1948
	File number 2-8398, as Exhibit 7-a-6, Fifth, November 1, 1949
	File number 2-8973, as Exhibit 7-a-7, Sixth, October 1, 1951
	File number 2-12941, as Exhibit 2-C-8, Seventh, January 1, 1957
	File number 2-13688, as Exhibit 4-J, Eighth, July 15, 1957
	File number 2-13689, as Exhibit 4-K, Ninth, November 15, 1957
	File number 2-14245, as Exhibit 4-L, Tenth, April 1, 1958
	File number 2-14366, as Exhibit 2-L, Eleventh, October 15, 1958
	File number 2-14935, as Exhibit 4-N, Twelfth, May 15, 1959
	File number 2-18976, as Exhibit 4-O, Thirteenth, November 15, 1960
	File number 2-18977, as Exhibit 4-Q, Fourteenth, November 1, 1961
	File number 2-22988, as Exhibit 4-B-16, Fifteenth, September 15, 1964
	File number 2-24578, as Exhibit 4-B-17, Sixteenth, April 1, 1966
	File number 2-25479, as Exhibit 4-B-18, Seventeenth, October 1, 1966
	File number 2-45260, as Exhibit 2(c), Eighteenth, September 1, 1972
	File number 2-49854, as Exhibit 2(c), Nineteenth, January 15, 1974
	File number 2-51722, as Exhibit 2(c)(i), Twentieth, August 1, 1974
	File number 2-51722, as Exhibit 2(c)(ii), Twenty-first, October 15, 1974
	File number 2-57374, as Exhibit 2(c), Twenty-second, November 15, 1976
	File number 2-62035, as Exhibit 2(c), Twenty-third, August 15, 1978
	File number 33-34222, as Exhibit 4(d)(iii), Twenty-fourth, September 1, 1979
	File number 33-34222, as Exhibit 4(d)(iv), Twenty-fifth, November 1, 1981
	File number 33-34222, as Exhibit 4(d)(v), Twenty-sixth, May 1, 1982
	File number 33-34222, as Exhibit 4(d)(vi), Twenty-seventh, May 1, 1986
	File number 33-00440, as Exhibit 4(c)(iv), Twenty-eighth, June 30, 1989
	File number 33-34222, as Exhibit 4(d)(vii), Twenty-ninth, January 1, 1990
	File number 33-65720, as Exhibit 4(d)(iii), Thirtieth, January 1, 1991
	File number 33-65720, as Exhibit 4(d)(iv), Thirty-first, August 15, 1991

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		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith
	File number 33-65720, as Exhibit 4(d)(v), Thirty-second, March 15, 1992
	File number 33-65720, as Exhibit 4(d)(vi), Thirty-third, April 1, 1993
	File number 1-3198, Form 8-K, filed on 12/20/93, as Exhibit 4, Thirty-fourth, December 1, 1993
	File number 1-3198, Form 8-K, filed on 11/21/00, as Exhibit 4, Thirty-fifth, November 1, 2000
	File number 1-3198, Form 8-K, filed on 10/1/01, as Exhibit 4, Thirty-sixth, October 1, 2001
	File number 1-3198, Form 8-K, filed on 4/16/03, as Exhibit 4, Thirty-seventh, April 1, 2003
	File number 1-3198, Form 10-Q for the quarter ended June 30, 2003, filed on 8/7/03, as Exhibit 4(a)(iii), Thirty-eighth, May 15, 2003
	File number 1-3198, Form 10-Q for the quarter ended September 30, 2003, filed on 11/6/03, as Exhibit 4(a)(iv), Thirty-ninth, October 1, 2003
	File number 1-3198, Form 8-K filed on 5/10/05, as Exhibit 4, Fortieth, May 1, 2005
	File number 1-3198, Form 8-K filed on 10/10/06, as Exhibit 4, Forty-first, October 1, 2006
	File number 1-3198, Form 8-K filed on 6/4/07, as Exhibit 4, Forty-second, May 1, 2007
	File number 1-3198, Form 8-K filed on 9/26/07, as Exhibit 4, Forty-third, September 1, 2007
	File number 1-3198, Form 8-K filed on 4/3/08, as Exhibit 4, Forty-fourth, April 1, 2008
	File number 1-3198, Form 10-K filed on 2/23/10, as Exhibit 4.10, Forty-fifth, February 1, 2010
	File number 1-3198, Form 8-K filed on 6/18/10, as Exhibit 4, Forty-sixth, June 1, 2010
	File number 1-3198, Form 8-K filed on 7/12/2013, as Exhibit 4.1, Forty-seventh, July 1, 2013
	File number 1-3198, Form 8-K filed on 9/27/2016, as Exhibit 4.1, Forty-eighth, September 1, 2016
4.3	Instruments relating to Idaho Power Company American Falls bond guarantee (see Exhibit 10.24)	10-Q	1-3198	4(b)	8/4/2000
4.4	Agreement of Idaho Power Company to furnish certain debt instruments	S-3	33-65720	4(f)	7/7/1993
4.5	Agreement of IDACORP, Inc. to furnish certain debt instruments	10-Q	1-14465	4(c)(ii)	11/6/2003
4.6	Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine corporation, and Idaho Power Migrating Corporation	S-3 Post-Effective Amend. No. 2	33-00440	2(a)(iii)	6/30/1989
4.7	Indenture for Senior Debt Securities dated as of February 1, 2001, between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee	8-K	1-14465	4.1	2/28/2001
4.8	First Supplemental Indenture dated as of February 1, 2001 to Indenture for Senior Debt Securities dated as of February 1, 2001 between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee	8-K	1-14465	4.2	2/28/2001
4.9	Indenture for Debt Securities dated as of August 1, 2001 between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee	S-3	333-67748	4.13	8/16/2001
4.10	Idaho Power Company Instrument of Further Assurance relating to Mortgage and Deed of Trust, dated as of August 3, 2010	10-Q	1-3198	4.12	8/5/2010
10.1	Agreement, dated as of October 11, 1973, between Idaho Power Company and Pacific Power & Light Company		2-49584	5(c)
10.2	Amended and Restated Agreement for the Operation of the Jim Bridger Project, dated December 11, 2014, between Idaho Power Company and PacifiCorp	10-K	1-14465, 1-3198	10.4	2/19/2015
10.3	Amended and Restated Agreement for the Ownership of the Jim Bridger Project, dated December 11, 2014, between Idaho Power Company and PacifiCorp	10-K	1-14465, 1-3198	10.5	2/19/2015
10.4	Letter Agreement, dated January 23, 1976, between Idaho Power Company and Portland General Electric Company		2-56513	5(i)
10.5	Agreement for Construction, Ownership and Operation of the Number One Boardman Station on Carty Reservoir, dated as of October 15, 1976, between Portland General Electric Company and Idaho Power Company	S-7	2-62034	5(s)	6/30/1978

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		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith
10.6	Amendment, dated September 30, 1977, relating to the agreement filed as Exhibit 10.4	S-7	2-62034	5(t)	6/30/1978
10.7	Amendment, dated October 31, 1977, relating to the agreement filed as Exhibit 10.4	S-7	2-62034	5(u)	6/30/1978
10.8	Amendment, dated January 23, 1978, relating to the agreement filed as Exhibit 10.4	S-7	2-62034	5(v)	6/30/1978
10.9	Amendment, dated February 15, 1978, relating to the agreement filed as Exhibit 10.4	S-7	2-62034	5(w)	6/30/1978
10.10	Amendment, dated September 1, 1979, relating to the agreement filed as Exhibit 10.4	S-7	2-68574	5(x)	7/23/1980
10.11	Participation Agreement, dated September 1, 1979, relating to the sale and leaseback of coal handling facilities at the Number One Boardman Station on Carty Reservoir	S-7	2-68574	5(z)	7/23/1980
10.12	Agreements for the Operation, Construction and Ownership of the North Valmy Power Plant Project, dated December 12, 1978, between Sierra Pacific Power Company and Idaho Power Company	S-7	2-64910	5(y)	6/29/1979
10.13	Framework Agreement, dated October 1, 1984, between the State of Idaho and Idaho Power Company relating to Idaho Power Company's Swan Falls and Snake River water rights	S-3	33-65720	10(h)	7/7/1993
10.14	Agreement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.13	S-3	33-65720	10(h)(i)	7/7/1993
10.15	Contract to Implement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.13	S-3	33-65720	10(h)(ii)	7/7/1993
10.16	Settlement Agreement, dated March 25, 2009, between the State of Idaho and Idaho Power Company relating to the agreement filed as Exhibit 10.13	10-Q	1-14465	10.58	5/7/2009
10.17	Agreement Regarding the Ownership, Construction, Operation and Maintenance of the Milner Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between Idaho Power Company and the Twin Falls Canal Company and the Northside Canal Company Limited	S-3	33-65720	10(m)	7/7/1993
10.18	Credit Agreement, dated November 6, 2015, among IDACORP, Inc., Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein	8-K	1-14465, 1-3198	10.1	11/9/2015
10.19	Credit Agreement, dated November 6, 2015, among Idaho Power Company, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein	8-K	1-14465, 1-3198	10.2	11/9/2015
10.20	Letter Agreement, effective as of November 7, 2016, among IDACORP, Inc., Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending term of Credit Agreement					X

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		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith
10.21	Letter Agreement, effective as of November 7, 2016, among Idaho Power Company, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending term of Credit Agreement					X
10.22	Loan Agreement, dated October 1, 2006, between Sweetwater County, Wyoming and Idaho Power Company	8-K	1-3198	10.1	10/10/2006
10.23	Guaranty Agreement, dated February 10, 1992, between Idaho Power Company and New York Life Insurance Company, as Note Purchaser, relating to $11,700,000 Guaranteed Notes due 2017 of Milner Dam Inc.	S-3	33-65720	10(m)(i)	7/7/1993
10.24	Guaranty Agreement, dated April 11, 2000, between Idaho Power Company and Bank One Trust Company, N.A., as Trustee, relating to $19,885,000 American Falls Replacement Dam Refinancing Bonds of the American Falls Reservoir District, Idaho	10-Q	1-3198	10(c)	8/4/2000
10.25	Guaranty Agreement, dated as of August 30, 1974, between Idaho Power Company and Pacific Power & Light Company	S-7	2-62034	5(r)	6/30/1978
10.26 ¹	Idaho Power Company Security Plan for Senior Management Employees I, amended and restated effective December 31, 2004, and as further amended November 20, 2008	10-K	1-14465, 1-3198	10.15	2/26/2009
10.27 ¹	Amendment, dated September 19, 2012, to the Idaho Power Company Security Plan for Senior Management Employees I	10-Q	1-14465, 1-3198	10.62	11/1/2012
10.28 ¹	Idaho Power Company Security Plan for Senior Management Employees II, effective January 1, 2005, as amended and restated November 30, 2011 (superseded by Exhibit 10.31 effective February 9, 2017)	10-K	1-14465, 1-3198	10.21	2/22/2012
10.29 ¹	Amendment, dated September 19, 2012, to the Idaho Power Company Security Plan for Senior Management Employees II (superseded by Exhibit 10.31 effective February 9, 2017)	10-Q	1-14465, 1-3198	10.63	11/1/2012
10.30 ¹	Amendment, dated January 16, 2014, to the Idaho Power Company Security Plan for Senior Management Employees II (superseded by Exhibit 10.31 effective February 9, 2017)	10-K	1-14465, 1-3198	10.26	2/20/2014
10.31 ¹	Idaho Power Company Security Plan for Senior Management Employees II, as amended and restated February 9, 2017					X
10.32 ¹	IDACORP, Inc. Restricted Stock Plan, as amended and restated September 20, 2007 (terminated February 9, 2017)	10-Q	1-14465, 1-3198	10(h)(iii)	10/31/2007
10.33 ¹	Idaho Power Company Security Plan for Board of Directors - a non-qualified deferred compensation plan, as amended and restated effective July 20, 2006	10-Q	1-14465, 1-3198	10(h)(viii)	11/2/2006
10.34 ¹	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan, as amended November 19, 2015	10-K	1-14465, 1-3198	10.34	2/18/2016
10.35 ¹	Form of Officer Indemnification Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power Company, as amended July 20, 2006	10-Q	1-14465, 1-3198	10(h)(xix)	11/2/2006
10.36 ¹	Form of Director Indemnification Agreement between IDACORP, Inc. and Directors of IDACORP, Inc., as amended July 20, 2006	10-Q	1-14465, 1-3198	10(h)(xx)	11/2/2006
10.37 ¹	Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and Idaho Power Company (senior vice president and higher), approved November 20, 2008	10-K	1-14465, 1-3198	10.24	2/26/2009
10.38 ¹	Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and Idaho Power Company (below senior vice president), approved November 20, 2008	10-K	1-14465, 1-3198	10.25	2/26/2009
10.39 ¹	Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power Company, approved March 17, 2010	8-K	1-14465, 1-3198	10.1	3/24/2010

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		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith
10.40 ¹	IDACORP, Inc. and/or Idaho Power Company Executive Officers with Amended and Restated Change in Control Agreements chart, as of February 8, 2017					X
10.41 ¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended and restated February 9, 2017					X
10.42 ¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Unit Award Agreement (Time Vesting)					X
10.43 ¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Total Shareholder Return Goal)					X
10.44 ¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Cumulative Earnings Per Share Goal)					X
10.45 ¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Stock Award Agreement (Time Vesting) (For 2015 and 2016 Outstanding Awards)	10-K	1-14465, 1-3198	10.43	2/19/2015
10.46 ¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Share Award Agreement (Performance with Two Goals) (For 2015 and 2016 Outstanding Awards)	10-K	1-14465, 1-3198	10.44	2/19/2015
10.47 ¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Stock Award Agreement (Time Vesting) (For 2014 and Prior Outstanding Awards)	10-Q	1-14465, 1-3198	10(h)(xvii)	11/2/2006
10.48 ¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Share Award Agreement (Performance with Two Goals) (For 2014 and Prior Outstanding Awards)	10-Q	1-14465, 1-3198	10.69	5/5/2011
10.49 ¹	IDACORP, Inc. Executive Incentive Plan, as amended and restated February 11, 2016	10-K	1-14465, 1-3198	10.47	2/18/2016
10.50 ¹	Idaho Power Company Executive Deferred Compensation Plan, effective November 15, 2000, as amended November 20, 2008	10-K	1-14465, 1-3198	10.32	2/26/2009
10.51 ¹	IDACORP, Inc. and Idaho Power Company Compensation for Non-Employee Directors of the Board of Directors, effective January 1, 2017					X
10.52 ¹	Form of IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008	10-K	1-14465, 1-3198	10.46	2/26/2009
10.53 ¹	Form of Letter Agreement to Amend Outstanding IDACORP, Inc. Director Deferred Compensation Agreement (November 16, 2008)	10-K	1-14465, 1-3198	10.47	2/26/2009
10.54 ¹	Form of Amendment to IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008	10-K	1-14465, 1-3198	10.48	2/26/2009
10.55 ¹	Form of Termination of IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008	10-K	1-14465, 1-3198	10.49	2/26/2009
10.56 ¹	Form of Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008	10-K	1-14465, 1-3198	10.50	2/26/2009
10.57 ¹	Form of Letter Agreement to Amend Outstanding Idaho Power Company Director Deferred Compensation Agreement (November 16, 2008)	10-K	1-14465, 1-3198	10.51	2/26/2009
10.58 ¹	Form of Amendment to Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008	10-K	1-14465, 1-3198	10.52	2/26/2009
10.59 ¹	Form of Termination of Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008	10-K	1-14465, 1-3198	10.53	2/26/2009
10.60 ¹	Idaho Power Company Restated Employee Savings Plan, as restated as of January 1, 2016	10-K	1-14465, 1-3198	10.59	2/18/2016
10.61 ¹	Amendment, dated effective December 1, 2016, to the Idaho Power Company Restated Employee Savings Plan, as restated as of January 1, 2016					X
12.1	IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges					X

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		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith
12.2	Idaho Power Company Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges					X
21.1	Subsidiaries of IDACORP, Inc.	10-K	1-14465, 1-3198	21.1	2/21/2013
23.1	Consent of Registered Independent Accounting Firm					X
23.2	Consent of Registered Independent Accounting Firm					X
31.1	IDACORP, Inc. Rule 13a-14(a) CEO certification					X
31.2	IDACORP, Inc. Rule 13a-14(a) CFO certification					X
31.3	Idaho Power Rule 13a-14(a) CEO certification					X
31.4	Idaho Power Rule 13a-14(a) CFO certification					X
32.1	IDACORP, Inc. Section 1350 CEO certification					X
32.2	IDACORP, Inc. Section 1350 CFO certification					X
32.3	Idaho Power Section 1350 CEO certification					X
32.4	Idaho Power Section 1350 CFO certification					X
95.1	Mine Safety Disclosures					X
101.INS	XBRL Instance Document					X
101.SCH	XBRL Taxonomy Extension Schema Document					X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document					X
101.LAB	XBRL Taxonomy Extension Label Linkbase Document					X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					X
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document					X

¹ Management contract or compensatory plan or arrangement

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IDACORP, INC.

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME



	Year Ended December 31,
	2016			2015			2014
	(thousands of dollars)
Income:
Equity in income of subsidiaries	$	198,061		$	194,426		$	193,707
Investment income	3			1			—
Total income	198,064			194,427			193,707
Expenses:
Operating expenses	716			831			1,376
Interest expense	333			276			261
Other expenses	45			45			45
Total expenses	1,094			1,152			1,682
Income from Before Income Taxes	196,970			193,275			192,025
Income Tax Benefit	(1,318		)	(1,404		)	(1,455		)
Net Income Attributable to IDACORP, Inc.	198,288			194,679			193,480
Other comprehensive income (loss)	394			2,882			(7,605		)
Comprehensive Income Attributable to IDACORP, Inc.	$	198,682		$	197,561		$	185,875

The accompanying note is an integral part of these statements.

IDACORP, INC.

CONDENSED STATEMENTS OF CASH FLOWS



	Year Ended December 31,
	2016			2015			2014
	(thousands of dollars)
Operating Activities:
Net cash provided by operating activities	$	139,077		$	100,465		$	109,289
Investing Activities:
Net cash provided by (used in) investing activities	—			—			—
Financing Activities:
Dividends on common stock	(104,985		)	(96,810		)	(88,489		)
(Decrease) increase in short-term borrowings	(20,000		)	(11,300		)	(23,450		)
Change in intercompany notes payable	2,421			5,572			(198		)
Other	(3,422		)	(1,675		)	(274		)
Net cash used in financing activities	(125,986		)	(104,213		)	(112,411		)
Net (decrease) increase in cash and cash equivalents	13,091			(3,748		)	(3,122		)
Cash and cash equivalents at beginning of year	2,028			5,776			8,898
Cash and cash equivalents at end of year	$	15,119		$	2,028		$	5,776

The accompanying note is an integral part of these statements.

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IDACORP, INC.

CONDENSED BALANCE SHEETS



	December 31,
	2016		2015
Assets	(thousands of dollars)
Current Assets:
Cash and cash equivalents	$	15,119	$	2,028
Receivables	1,065		946
Income taxes receivable	—		7,241
Other	101		119
Total current assets	16,285		10,334
Investment in subsidiaries	2,098,818		2,007,984
Other Assets:
Deferred income taxes	66,411		76,410
Other	385		402
Total other assets	66,796		76,812
Total assets	$	2,181,899	$	2,095,130
Liabilities and Shareholders’ Equity
Current Liabilities:
Notes payable	$	—	$	20,000
Accounts payable	6		13
Taxes accrued	8,476		—
Other	660		765
Total current liabilities	9,142		20,778
Other Liabilities:
Intercompany notes payable	17,834		15,292
Other	1,017		1,175
Total other liabilities	18,851		16,467
IDACORP, Inc. Shareholders’ Equity	2,153,906		2,057,885
Total Liabilities and Shareholders' Equity	$	2,181,899	$	2,095,130
The accompanying note is an integral part of these statements.

NOTE TO CONDENSED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

Pursuant to rules and regulations of the U.S. Securities and Exchange Commission, the unconsolidated condensed financial statements of IDACORP, Inc. do not reflect all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and related notes included in the 2016 Form 10-K, Part II, Item 8.

Accounting for Subsidiaries: IDACORP has accounted for the earnings of its subsidiaries under the equity method of accounting in these unconsolidated condensed financial statements. Included in net cash provided by operating activities in the condensed statements of cash flows are dividends that IDACORP subsidiaries paid to IDACORP of $108 million , $99 million , and $91 million in 2016 , 2015 , and 2014 , respectively.

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IDACORP, INC.

SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2016 , 2015 , and 2014



Column A	Column B		Column C					Column D		Column E
			Additions
						Charged
	Balance at		Charged			(Credited)				Balance at
	Beginning		to			to Other				End
Classification	of Year		Income			Accounts		Deductions ⁽¹⁾		of Year
	(thousands of dollars)
2016:
Reserves deducted from applicable assets
Reserve for uncollectible accounts	$	1,355	$	3,917		$	263	$	4,403	$	1,132
Reserve for uncollectible notes	552		—			—		150		402
Other Reserves:
Injuries and damages	1,874		848			—		930		1,792
2015:
Reserves deducted from applicable assets
Reserve for uncollectible accounts	$	2,104	$	3,327		$	819	$	4,895	$	1,355
Reserve for uncollectible notes	552		—			—		—		552
Other Reserves:
Injuries and damages	1,995		890			—		1,011		1,874
2014:
Reserves deducted from applicable assets
Reserve for uncollectible accounts	$	2,502	$	6,756		$	198	$	7,352	$	2,104
Reserve for uncollectible notes	885		(333		)	—		—		552
Other Reserves:
Rate refunds	398		(398		)	—		—		—
Injuries and damages	1,671		461			—		137		1,995

⁽¹⁾ Represents deductions from the reserves for purposes for which the reserves were created. In the case of uncollectible accounts, and notes reserves, includes reversals of amounts previously reserved.

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IDAHO POWER COMPANY

SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2016 , 2015 , and 2014



Column A	Column B		Column C					Column D		Column E
			Additions
						Charged
	Balance at		Charged			(Credited)				Balance at
	Beginning		to			to Other				End
Classification	of Year		Income			Accounts		Deductions ⁽¹⁾		of Year
	(thousands of dollars)
2016:
Reserves deducted from applicable assets
Reserve for uncollectible accounts	$	1,355	$	3,917		$	263	$	4,403	$	1,132
Other Reserves:
Injuries and damages	1,874		848			—		930		1,792
2015:
Reserves deducted from applicable assets
Reserve for uncollectible accounts	$	2,104	$	3,327		$	819	$	4,895	$	1,355
Other Reserves:
Injuries and damages	1,995		890			—		1,011		1,874
2014:
Reserves deducted from applicable assets
Reserve for uncollectible accounts	$	2,502	$	6,756		$	198	$	7,352	$	2,104
Other Reserves:
Rate refunds	398		(398		)	—		—		—
Injuries and damages	1,671		461			—		137		1,995

⁽¹⁾ Represents deductions from the reserves for purposes for which the reserves were created. In the case of uncollectible accounts, includes reversals of amounts previously reserved.

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SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



February 23, 2017		IDACORP, INC.
Date
	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Title	Date

/s/ Robert A. Tinstman	Chairman of the Board	February 23, 2017
Robert A. Tinstman

/s/ Darrel T. Anderson	(Principal Executive Officer)	February 23, 2017
Darrel T. Anderson
President and Chief Executive Officer and Director

/s/ Steven R. Keen	(Principal Financial Officer)	February 23, 2017
Steven R. Keen
Senior Vice President, Chief Financial
Officer, and Treasurer

/s/ Kenneth W. Petersen	(Principal Accounting Officer)	February 23, 2017
Kenneth W. Petersen
Vice President, Controller, and Chief Accounting Officer

/s/ Thomas Carlile	Director	February 23, 2017
Thomas Carlile

/s/ Richard J. Dahl	Director	February 23, 2017
Richard J. Dahl

/s/ Annette G. Elg	Director	February 23, 2017
Annette G. Elg

/s/ Ronald W. Jibson	Director	February 23, 2017
Ronald W. Jibson

/s/ Judith A. Johansen	Director	February 23, 2017
Judith A. Johansen

/s/ Dennis L. Johnson	Director	February 23, 2017
Dennis L. Johnson

/s/ J. LaMont Keen	Director	February 23, 2017
J. LaMont Keen

/s/ Christine King	Director	February 23, 2017
Christine King

/s/ Richard J. Navarro	Director	February 23, 2017
Richard J. Navarro

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SIGNATURES



February 23, 2017		Idaho Power Company
Date
	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer



Signature	Title	Date

/s/ Robert A. Tinstman	Chairman of the Board	February 23, 2017
Robert A. Tinstman

/s/ Darrel T. Anderson	(Principal Executive Officer)	February 23, 2017
Darrel T. Anderson
President and Chief Executive Officer and Director

/s/ Steven R. Keen	(Principal Financial Officer)	February 23, 2017
Steven R. Keen
Senior Vice President, Chief Financial
Officer, and Treasurer

/s/ Kenneth W. Petersen	(Principal Accounting Officer)	February 23, 2017
Kenneth W. Petersen
Vice President, Controller, and Chief Accounting Officer

/s/ Thomas Carlile	Director	February 23, 2017
Thomas Carlile

/s/ Richard J. Dahl	Director	February 23, 2017
Richard J. Dahl

/s/ Annette G. Elg	Director	February 23, 2017
Annette G. Elg

/s/ Ronald W. Jibson	Director	February 23, 2017
Ronald W. Jibson

/s/ Judith A. Johansen	Director	February 23, 2017
Judith A. Johansen

/s/ Dennis L. Johnson	Director	February 23, 2017
Dennis L. Johnson

/s/ J. LaMont Keen	Director	February 23, 2017
J. LaMont Keen

/s/ Christine King	Director	February 23, 2017
Christine King

/s/ Richard J. Navarro	Director	February 23, 2017
Richard J. Navarro

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EXHIBIT INDEX



Exhibit No.	Description

10.20	Letter Agreement, effective as of November 7, 2016, among IDACORP, Inc., Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending term of Credit Agreement
10.21	Letter Agreement, effective as of November 7, 2016, among Idaho Power Company, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and MUFG Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending term of Credit Agreement
10.31 ¹	Idaho Power Company Security Plan for Senior Management Employees II, as amended and restated February 9, 2017
10.40 ¹	IDACORP, Inc. and/or Idaho Power Company Executive Officers with Amended and Restated Change in Control Agreements chart, as of February 8, 2017
10.41 ¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended and restated February 9, 2017
10.42 ¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Unit Award Agreement (Time Vesting)
10.43 ¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Total Shareholder Return Goal)
10.44 ¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Cumulative Earnings Per Share Goal)
10.51 ¹	IDACORP, Inc. and Idaho Power Company Compensation for Non-Employee Directors of the Board of Directors, effective January 1, 2017
10.61 ¹	Amendment, dated effective December 1, 2016, to the Idaho Power Company Restated Employee Savings Plan, as restated as of January 1, 2016
12.1	IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
12.2	Idaho Power Company Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
23.1	Consent of Independent Registered Public Accounting Firm
23.2	Consent of Independent Registered Public Accounting Firm
31.1	IDACORP, Inc. Rule 13a-14(a) CEO certification
31.2	IDACORP, Inc. Rule 13a-14(a) CFO certification
31.3	Idaho Power Rule 13a-14(a) CEO certification
31.4	Idaho Power Rule 13a-14(a) CFO certification
32.1	IDACORP, Inc. Section 1350 CEO certification
32.2	IDACORP, Inc. Section 1350 CFO certification
32.3	Idaho Power Section 1350 CEO certification
32.4	Idaho Power Section 1350 CFO certification
95.1	Mine Safety Disclosures
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

⁽¹⁾ Management contract or compensatory plan or arrangement.

147

Exhibit 10.20

October 3, 2016



To:	Idaho Power Company/IDACORP, Inc. Bank Group

From:	Wells Fargo Bank, National Association, as Administrative Agent


Re:	(i) Idaho Power Company $300 Million Credit Agreement dated as of November 6, 2015 (the “ Idaho Power Credit Agreement ”) and (ii) IDACORP, Inc. $100 Million Credit Agreement dated as of November 6, 2015 (the “ IDACORP, Inc. Credit Agreement ” and together with the Idaho Power Credit Agreement, the “ Credit Agreements ”)

Reference is hereby made to the Credit Agreements described above. Capitalized terms used herein without definition shall have the meanings ascribed to such terms in the Credit Agreements.

Pursuant to Section 2.21(a) of the Idaho Power Credit Agreement, Idaho Power Company has requested that the Facility Termination Date be extended for an additional year until November 5, 2021. Idaho Power Company has agreed to pay each Lender approving the extension a fee equal to 0.06% of such Lender’s Commitment; provided that such fee shall be payable only in the event that the extension of the Facility Termination Date until November 5, 2021 is approved in accordance with Section 2.21(b) of the Idaho Power Credit Agreement.

Pursuant to Section 2.21(a) of the IDACORP, Inc. Credit Agreement, IDACORP, Inc. has requested that the Facility Termination Date be extended for an additional year until November 5, 2021. IDACORP, Inc. has agreed to pay each Lender approving the extension a fee equal to 0.06% of such Lender’s Commitment; provided that such fee shall be payable only in the event that the extension of the Facility Termination Date until November 5, 2021 is approved in accordance with Section 2.21(b) of the IDACORP, Inc. Credit Agreement.

Please insert your institution’s name and indicate on the following page whether you consent to the requested extension of the Facility Termination Date for each of the Idaho Power Credit Agreement and the IDACORP, Inc. Credit Agreement until November 5, 2021, and email a PDF copy of this letter to Sharika Robinson at Robinson, Bradshaw & Hinson, P.A. (srobinson@robinsonbradshaw.com).

Your response is requested prior to 5:00 p.m. (EDT) on October 18, 2016 .

Please contact Catherine Coles (phone: 415.834.4822; email: catherine.coles @wellsfargo.com ) or Chase Alexander (phone: 704.410.4692; email: chase.alexander@wellsfargo.com) if you have any questions.

Thank you for your attention to this matter.

JPMorgan Chase Bank, N.A. hereby (select one):


___ ü _	CONSENTS to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.


___ ü _	CONSENTS to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

By: /s/ Nancy R. Barwig

Name: Nancy R. Barwig

Title: Credit Risk Director

Date: October 17 , 2016

Wells Fargo Bank, NA hereby (select one):

Lender Name


___X_	CONSENTS to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.


___X_	CONSENTS to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

By: /s/ Gregory R. Gredvig

Name: Gregory R. Gredvig

Title: Vice President

Date: October 11, 2016

US Bank, National Association hereby:


X	CONSENTS to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.


X	CONSENTS to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

By: /s/ Holland H. Williams

Name: Holland H. Williams

Title: Vice President

Date: October 11, 2016, 2016

KeyBank National Association hereby (select one):

Lender Name


___X_	CONSENTS to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.


___X_	CONSENTS to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

By: /s/ Keven D Smith

Name: Keven Smith

Title: Senior Vice President

Date: October 17, 2016

THE BANK OF NEW YORK MELLON hereby (select one):


___X_	CONSENTS to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.


___X_	CONSENTS to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

By: /s/ Mark W. Rogers

Name: Mark W. Rogers

Title: Vice President

Date: October 17, 2016

MUFG UNION BANK, N.A. hereby (select one):

Lender Name


___X_	CONSENTS to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.


___X_	CONSENTS to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

By: /s/ Eric Otieno

Name: Eric Otieno

Title: Vice President

Date: October 18, 2016

Bank of America Merrill Lynch hereby (select one):

Lender Name


___X_	CONSENTS to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.


___X_	CONSENTS to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

By: /s/ Elisa Kang

Name: Elisa Kang

Title: SVP

Date: October 18, 2016

Exhibit 10.21

October 3, 2016



To:	Idaho Power Company/IDACORP, Inc. Bank Group

From:	Wells Fargo Bank, National Association, as Administrative Agent


Re:	(i) Idaho Power Company $300 Million Credit Agreement dated as of November 6, 2015 (the “ Idaho Power Credit Agreement ”) and (ii) IDACORP, Inc. $100 Million Credit Agreement dated as of November 6, 2015 (the “ IDACORP, Inc. Credit Agreement ” and together with the Idaho Power Credit Agreement, the “ Credit Agreements ”)

Reference is hereby made to the Credit Agreements described above. Capitalized terms used herein without definition shall have the meanings ascribed to such terms in the Credit Agreements.

Your response is requested prior to 5:00 p.m. (EDT) on October 18, 2016 .

Thank you for your attention to this matter.

JPMorgan Chase Bank, N.A. hereby (select one):


___ ü _	CONSENTS to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.


___ ü _	CONSENTS to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

By: /s/ Nancy R. Barwig

Name: Nancy R. Barwig

Title: Credit Risk Director

Date: October 17 , 2016

Wells Fargo Bank, NA hereby (select one):

Lender Name


___X_	CONSENTS to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.


___X_	CONSENTS to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

By: /s/ Gregory R. Gredvig

Name: Gregory R. Gredvig

Title: Vice President

Date: October 11, 2016

US Bank, National Association hereby:


X	CONSENTS to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.


X	CONSENTS to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

By: /s/ Holland H. Williams

Name: Holland H. Williams

Title: Vice President

Date: October 11, 2016, 2016

KeyBank National Association hereby (select one):

Lender Name


___X_	CONSENTS to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.


___X_	CONSENTS to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

By: /s/ Keven D Smith

Name: Keven Smith

Title: Senior Vice President

Date: October 17, 2016

THE BANK OF NEW YORK MELLON hereby (select one):


___X_	CONSENTS to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.


___X_	CONSENTS to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

By: /s/ Mark W. Rogers

Name: Mark W. Rogers

Title: Vice President

Date: October 17, 2016

MUFG UNION BANK, N.A. hereby (select one):

Lender Name


___X_	CONSENTS to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.


___X_	CONSENTS to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

By: /s/ Eric Otieno

Name: Eric Otieno

Title: Vice President

Date: October 18, 2016

Bank of America Merrill Lynch hereby (select one):

Lender Name


___X_	CONSENTS to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the Idaho Power Credit Agreement to November 5, 2021.


___X_	CONSENTS to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

______ DOES NOT consent to the extension of the Facility Termination Date under the IDACORP, Inc. Credit Agreement to November 5, 2021.

By: /s/ Elisa Kang

Name: Elisa Kang

Title: SVP

Date: October 18, 2016

Exhibit 10.31

IDAHO POWER COMPANY

SECURITY PLAN FOR

SENIOR MANAGEMENT EMPLOYEES II

Effective January 1, 2005

(Amended and Restated February 8, 2017)


ARTICLE I	PURPOSE; EFFECTIVE DATE ......................................................................................................1


ARTICLE II	DEFINITIONS......................................................................................................................................1


2.1	Actuarial Equivalent..............................................................................................................................2


2.2	Administrative Committee.....................................................................................................................2


2.3	Administrator.........................................................................................................................................2


2.4	Affiliate..................................................................................................................................................2


2.5	Beneficiary.............................................................................................................................................2


2.6	Board.....................................................................................................................................................2


2.7	Change in Control...................................................................................................................................2


2.8	Change in Control Period........................................................................................................................3


2.9	Code.......................................................................................................................................................3


2.10	Company................................................................................................................................................3


2.11	Compensation Committee......................................................................................................................3


2.12	Compensation........................................................................................................................................3


2.13	Disability................................................................................................................................................4


2.14	Early Retirement Date............................................................................................................................4


2.15	Employer................................................................................................................................................4


2.16	Final Average Monthly Compensation...................................................................................................4


2.17	Normal Retirement Date.........................................................................................................................4


2.18	Participant..............................................................................................................................................4

2.19 Plan Year................................................................................................................................................4


2.20	Retirement.............................................................................................................................................4


2.21	Retirement Plan ..................................................................................................................................4


2.22	Security Plan Retirement Benefit............................................................................................................4


2.23	Separation from Service ....................................................................................................................4


2.24	Target Retirement Percentage.................................................................................................................4


2.25	Termination Date....................................................................................................................................5


2.26	Years of Participation.............................................................................................................................5


ARTICLE III	PARTICIPATION AND VESTING........................................................................................................5


3.1	Eligibility...............................................................................................................................................5


3.2	Vesting of Benefits.................................................................................................................................6


3.3	Change in Employment Status................................................................................................................6


3.4	Non-Participating Affiliate.....................................................................................................................6


ARTICLE IV	SURVIVOR BENEFITS........................................................................................................................6


4.1	Pre-termination Survivor Benefit...........................................................................................................6


4.2	Post-termination Survivor Benefit..........................................................................................................7


4.3	Method of Payment................................................................................................................................7


4.4	Effect of Payment...................................................................................................................................9


4.5	Appendix A - Example Calculations.......................................................................................................9


ARTICLE V	SECURITY PLAN RETIREMENT BENEFITS....................................................................................9

TABLE OF CONTENTS

Page


5.1	Normal Retirement Benefit....................................................................................................................9


5.2	Early Retirement Benefit......................................................................................................................10


5.3	Early Retirement Factor ..................................................................................................................10


5.4	Early Termination Benefits...................................................................................................................11


5.5	Separation from Service After Change in Control.................................................................................11


5.6	Form of Payment..................................................................................................................................12


5.7	Code Section 162(m) Delay..................................................................................................................12


5.8	Payment to Specified Employees..........................................................................................................13


ARTICLE VI	OTHER RETIREMENT PROVISIONS..............................................................................................13


6.1	Disability..............................................................................................................................................13


6.2	Withholding Payroll Taxes...................................................................................................................13


6.3	Payment to Guardian\Conservator........................................................................................................13


ARTICLE VII	ADMINISTRATION...........................................................................................................................13


7.1	Administrative Committee Duties........................................................................................................13


7.2	Indemnity of Administrative Committee..............................................................................................14


ARTICLE VIII	CLAIMS PROCEDURE......................................................................................................................14


8.1	Claim...................................................................................................................................................14


8.2	Denial of Claim....................................................................................................................................14


8.3	Review of Claim...................................................................................................................................14

8.4 Final Decision......................................................................................................................................15


ARTICLE IX	TERMINATION, SUSPENSION OR AMENDMENT........................................................................15


9.1	Termination, Suspension or Amendment of Plan..................................................................................15


9.2	Change in Control.................................................................................................................................15


ARTICLE X	MISCELLANEOUS............................................................................................................................15


10.1	Unfunded Plan.....................................................................................................................................15


10.2	Unsecured General Creditor.................................................................................................................15


10.3	Trust Fund............................................................................................................................................16


10.4	Nonassignability.................................................................................................................................. 16


10.5	Not a Contract of Employment..............................................................................................................16


10.6	Governing Law.....................................................................................................................................16


10.7	Validity.................................................................................................................................................16


10.8	Notice..................................................................................................................................................16


10.9	Successors............................................................................................................................................16

IDAHO POWER COMPANY

SECURITY PLAN FOR SENIOR MANAGEMENT EMPLOYEES II

EFFECTIVE JANUARY 1, 2005

(Amended and Restated November 20, 2008)

(Amended and Restated November 19, 2009)

(Amended and Restated November 30, 2011)

(Amended and Restated February 8, 2017)

ARTICLE I

PURPOSE; EFFECTIVE DATE

The purpose of this Security Plan for Senior Management Employees II (the “Plan”) is to provide supplemental retirement benefits for certain key employees of Idaho Power Company, its subsidiaries and affiliates. It is intended that this Plan will aid in attracting individuals of exceptional ability and retain those critical to the operation of the Company, by providing them with these benefits. The effective date of this Plan is January 1, 2005. It is intended to be compliant with Section 409A of the Internal Revenue Code of 1986, as amended, and regulations and other guidance promulgated thereunder (collectively, “Section 409A”). It continues the program of supplemental retirement benefits provided under the Security Plan for Senior Management Employees I, which provides benefits that are grandfathered under Code Section 409A.

To the extent Code Section 409A is applicable to the Plan and the benefits provided hereunder, the Employer intends that the Plan comply with the deferral, payout and other limitations and restrictions imposed under Code Section 409A. Notwithstanding any provision of the Plan to the contrary, the Plan shall be interpreted, operated and administered in a manner consistent with such intention. Moreover, the Plan shall be deemed to be amended, and any elections hereunder shall be deemed to be modified, to the extent the Administrative Committee or Administrator determines to be necessary and effective to comply with the requirements of Code Section 409A and to avoid or mitigate the imposition of additional taxes under Code Section 409A, while preserving to the maximum extent possible the essential economics of the Participant's rights under the Plan.

ARTICLE II

DEFINITIONS

As used in this Plan, the following terms shall be defined as stated in this Article, as interpreted by the Administrative Committee pursuant to its authority granted by Section 7.1 of this Plan.

2.1 Actuarial Equivalent . “Actuarial Equivalent” shall mean equivalence in value between two (2) or more forms and/or times of payment based on a determination by an actuary chosen by the Company using generally accepted actuarial assumptions, methods and factors as determined by policy of the Administrative Committee, which may be amended from time to time.

2.2 Administrative Committee . “Administrative Committee” shall mean the Fiduciary Committee appointed by the Compensation Committee pursuant to Section 7.1 hereof and the Chief Executive Officer of the Company.

2.3 Administrator . “Administrator” shall mean the person designated by the Administrative Committee to perform certain administrative functions outlined in this Plan.

2.4 Affiliate . “Affiliate” shall mean a business entity that is affiliated in ownership with the Company and is recognized as an Affiliate by the Company for the purposes of this Plan.

2.5 Beneficiary . “Beneficiary” shall mean the person, persons or entity designated pursuant to Section 4.3.4 to receive any benefits payable under this Plan. Each such designation shall be made in a written instrument filed with the Administrative Committee and shall become effective only when received, accepted and acknowledged in writing by the Administrative Committee or its designee.

2.6 Board . “Board” shall mean the Board of Directors of the Company.

2.7 Change in Control . “Change in Control” shall mean any of the following events:

2.7.1 any person (as such term is defined in Section 3(a)(9) of the Securities Exchange Act of 1934 (the "Exchange Act") and as used in Section 13(d) of the Exchange Act, excluding (a) IDACORP, Inc. or any Subsidiary, (b) a corporation or other entity owned, directly or indirectly, by the stockholders of IDACORP, Inc. immediately prior to the transaction in substantially the same proportions as their ownership of stock of IDACORP, Inc., (c) an employee benefit plan (or related trust) sponsored or maintained by IDACORP, Inc. or any Subsidiary or (d) an underwriter temporarily holding securities pursuant to an offering of such securities (“Exchange Act Person”)) is the beneficial owner (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of 20% or more of the combined voting power of the then outstanding voting securities eligible to vote generally in the election of directors of IDACORP, Inc.; provided, however, that no Change in Control will be deemed to have occurred as a result of a change in ownership percentage resulting solely from an acquisition of securities by IDACORP, Inc.;

2.7.2 consummation of a merger, consolidation, reorganization or share exchange, or sale of all or substantially all of the assets, of IDACORP, Inc. or the Company (a “Qualifying Transaction”), unless, immediately following such Qualifying Transaction, all of the following have occurred: (a) all or substantially all of the beneficial owners of IDACORP, Inc. immediately prior to such Qualifying Transaction beneficially own in substantially the same proportions, directly or indirectly, more than 50% of the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors of the corporation or other entity resulting from such Qualifying Transaction (including, without limitation, a corporation or other entity which, as a result of such transaction, owns IDACORP, Inc. or all or substantially all of IDACORP, Inc.’s assets either directly or through one or more subsidiaries) (as the case may be, the “Successor Entity”), (b) no Exchange Act Person is the beneficial owner (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of 20% or more of the combined voting power of the then outstanding voting securities eligible to vote

generally in the election of directors of the Successor Entity and (c) at least a majority of the members of the board of directors of the Successor Entity are Incumbent Directors;

2.7.3 a complete liquidation or dissolution of IDACORP, Inc. or the Company; or

2.7.4 within a 24-month period, individuals who were directors of the Board of Directors of IDACORP, Inc. (the “IDACORP Board of Directors”) immediately before such period (“Incumbent Directors”) cease to constitute at least a majority of the directors of the IDACORP Board of Directors; provided, however, that any director who was not a director of the IDACORP Board of Directors at the beginning of such period shall be deemed to be an Incumbent Director if the election or nomination for election of such director was approved by the vote of at least two-thirds of the directors of the IDACORP Board of Directors then still in office (a) who were in office at the beginning of the 24-month period or (b) whose election or nomination for election was so approved, in each case, unless such individual was elected or nominated as a result of an actual or threatened election contest or as a result of an actual or threatened solicitation of proxies or consents by or on behalf of any Exchange Act Person other than the IDACORP Board of Directors.

For avoidance of doubt, transactions for the purpose of dividing the Company’s assets into separate distribution, transmission or generation entities or such other entities as IDACORP, Inc. or the Company may determine shall not constitute a Change in Control unless so determined by the IDACORP Board of Directors. For purposes of this definition, the term "Subsidiary" shall mean any corporation of which more than 50% of the outstanding stock having ordinary voting power to elect a majority of the board of directors of such corporation is now or hereafter owned, directly or indirectly, by IDACORP, Inc.

2.8 Change in Control Period . “Change in Control Period” shall mean the period beginning with a Change in Control and ending 24 months following the consummation of a Change in Control.

2.9 Code . “Code” shall mean the Internal Revenue Code of 1986, as amended.

2.10 Company . “Company” shall mean the Idaho Power Company, an Idaho corporation, its successors and assigns.

2.11 Compensation Committee . “Compensation Committee” shall mean the Board committee assigned responsibility for administering executive compensation.

2.12 Compensation . “Compensation” shall mean the base salary and annual incentive (not to exceed one (1) times base salary for the year in which the incentive was paid) paid to a Participant and considered to be "wages" for purposes of federal income tax withholding. Compensation shall be calculated before reduction for any amounts deferred by the Participant pursuant to any plan sponsored by the Employer which permits deferral of current compensation. Compensation does not include long-term incentive compensation in any form, expense reimbursements, or any form of non-cash compensation or benefits. A Participant who elects an accelerated distribution under the Security Plan for Senior Management Employees I, shall not be credited with any additional Compensation under this Plan beginning on the effective date of the accelerated distribution.

2.13 Disability . “Disability” shall mean that a Participant is eligible to receive benefits under the Long-Term Disability Program maintained by the Employer.

2.14 Early Retirement Date . “ Early Retirement Date” shall mean a Participant’s Termination Date, if such Termination Date occurs on or after such Participant’s:

2.14.1 attainment of age fifty-five (55); or

2.14.2 completion of thirty (30) years of Credited Service under the Retirement Plan but prior to Participant’s Normal Retirement Date.

2.15 Employer . “Employer” shall mean the Company.

2.16 Final Average Monthly Compensation . “Final Average Monthly Compensation” shall mean the Compensation received by the Participant during any sixty (60) consecutive months (during the last ten (10) years of employment) for which the Participant's compensation was the highest divided by sixty (60). For purposes of determining Final Average Monthly Compensation, annual cash incentive payments shall be included as Compensation in the month in which it was paid. Final Average Monthly Compensation shall not include any Compensation payable to a Participant pursuant to a written severance agreement with the Employer.

2.17 Normal Retirement Date . “Normal Retirement Date” shall mean a Participant’s Termination Date if the Termination Date occurs on or after the date the Participant attains age sixty-two.

2.18 Participant . “Participant” shall mean any individual who is participating in or has participated in this Plan as provided in Article III.

2.19 Plan Year . “Plan Year” shall mean the calendar year.

2.20 Retirement . “Retirement” shall mean a Participant’s Separation from Service at the Participant’s Early Retirement Date or Normal Retirement Date, as applicable.

2.21 Retirement Plan . “Retirement Plan” shall mean The Retirement Plan of Idaho Power Company as may be amended from time to time.

2.22 Security Plan Retirement Benefit . “Security Plan Retirement Benefit” shall mean the benefit determined under Article V of this Plan.

2.23 Separation from Service . “Separation from Service” shall mean “separation from service”, as that term is used in Section 409A(a)(2)(A)(i) of the Code.

2.24 Target Retirement Percentage .

2.24.1 For Participants of this Plan as of December 31, 2009, “Target Retirement Percentage” shall equal six percent (6%) for each of the first ten (10) Years of Participation plus an

additional one percent (1%) for each Year of Participation, exceeding ten (10). The maximum Target Retirement Percentage for these Participants shall be seventy-five percent (75%).

2.24.2 For Participants who become eligible to participate in this Plan on or after January 1, 2010, “Target Retirement Percentage” shall equal five percent (5%) for each of the first ten (10) Years of Participation plus an additional one percent (1%) for each Year of Participation exceeding ten (10). The maximum Target of Retirement Percentage for these Participants shall be sixty-five percent (65%).

2.24.3 Effective January 1, 2018, Participants who are officers of the Company and Participants who are in a job classification with a pay grade of S4 will accrue benefits according to the formula set forth in paragraph 2.24.2. This change to the applicable benefit formula shall not, in any way, change or alter the status of a Participant’s accrued benefits as of December 31, 2017.

2.24.4 Effective January 1, 2018, all Participants, other than officers of the Company and Participants who are in a job classification with a pay grade of S4, will have no increase to their Target Retirement Percentage. Although participation in this Plan by these Participants may continue beyond January 1, 2018, the Target Retirement Percentage accrued through this Plan will be frozen as of December 31, 2017.

2.25 Termination Date . “Termination Date” shall mean the date the Participant experiences a Separation from Service (other than due to death) by resignation, discharge, Retirement or any other method.

2.26 Years of Participation . “Years of Participation” shall be twelve (12) month periods, and portions thereof, which shall begin on the earlier of the date an individual, who has been designated by the Employer, is approved by the Administrative Committee pursuant to Section 3.1, or the date designated by the Administrative Committee, and shall end on the earliest of (i) the Participant's death, (ii) the Participant’s Termination Date, (iii) the date the Participant experiences a change in status, as provided in Sections 3.3 and 3.4, and (iv) if available and elected, the effective date of an accelerated distribution under the Security Plan for Senior Management Employees I. Partial Years of Participation, if any, shall be rounded up to the next full month and shall be used in determining benefits under this Plan. Years of Participation under the Security Plan for Senior Management Employees I, if any, shall be included in determining the total Years of Participation.

ARTICLE III

PARTICIPATION AND VESTING

3.1 Eligibility . Effective January 1, 2010, eligibility to participate in this Plan is limited to officers of the Employer and employees who are in job classifications with a pay grade of S4. Key employees, who as of January 1, 2005 are participants in the Security Plan for Senior Management Employees I, shall be Participants in this Plan on January 1, 2005, the effective date of this Plan. A key employee who, as of December 31, 2009, is a Participant in this Plan shall maintain eligibility to

participate in this Plan, so long as the Participant maintains a senior manager or officer pay grade during the Participant’s continuous employment with Employer.

3.2 Vesting of Benefits . For Participants who became eligible to participate in this Plan on or after January 1, 2010, the following vesting schedule applies to all benefits accrued through this Plan:

Years of Participations Vested Percentage

Less than 5 years 0%

5 years or more 100%

All Participants who, as of December 31, 2009, participate in this Plan shall be one hundred percent (100%) vested with all benefits earned through continuous employment with Employer.

3.3 Change in Employment Status . If the Employer determines that a Participant’s employment performance or classification is no longer at a level which deserves participation in this Plan, but the Participant has not experienced a Separation from Service, participation herein and eligibility to receive benefits hereunder shall be limited to the Participant’s accrued benefit as of the date of the change in employment status. In such an event, the benefits payable to the Participant shall be based solely on the Participant’s Years of Participation and Final Average Monthly Compensation as of the Termination Date. A Participant, who is not continuing participation in this Plan under this Section, will not have benefits determined nor receive benefits under Article V until the first to occur of his or her death or Termination Date.

3.4 Non-Participating Affiliate . A Participant, who subsequently is transferred to an Affiliate, may be allowed to continue participation under this Plan subject to the approval of the Administrative Committee. A Participant, who is not allowed to continue participation in this Plan, will not have benefits determined nor receive benefits under Article V until the first to occur of his or her death or Termination Date.

ARTICLE IV

SURVIVOR BENEFITS

4.1 Pre-termination Survivor Benefit . If a Participant dies before his or her Termination Date, the Employer shall pay a survivor benefit (paid in accordance with Section 4.3) to the Participant’s Beneficiary(ies) in an amount equal to the greater of:

4.1.1 the sum of (a) sixty-six and two-thirds percent (66 2/3%) of the Normal Retirement Benefit calculated under Section 5.1, determined without offsets in Sections 5.1.1 and 5.1.2, assuming retirement occurred at the later of (i) age sixty-two (62) with Years of Participation to age sixty-two (62) or (ii) the date of death, (b) less the death benefit paid, if any, determined in Section 4.01 of the Retirement Plan, and (c) less the death benefit paid, if any, determined in accordance with the Security Plan for Senior Management Employees I; or,

4.1.2 if death occurs after eligibility for Early Retirement under Section 2.14, a joint and survivor annuity with payments continued to the Participant’s Beneficiary(ies) at an amount equal to sum of (a) the Actuarial Equivalent of the Participant’s benefit calculated under Section 5.2, determined without offsets in Sections 5.2.1 and 5.2.2, assuming retirement occurred at the date of death, (b) less the death benefit paid, if any, determined in accordance with the Retirement Plan, and (c) less the death benefit paid, if any, determined in accordance with the Security Plan for Senior Management Employees I. Solely for purposes of this Section 4.1.2 and the calculation of the Actuarial Equivalent amount of the joint and survivor annuity benefit, the deceased Participant, regardless of marital status at the time of death, shall be deemed to have been married at the time of death to a spouse of the same age as the Participant.

Final Average Monthly Compensation and the Retirement Plan benefit shall be determined as of the date of the Participant’s death.

4.2 Post-termination Survivor Benefit .

4.2.1 Death Prior to Commencement of Benefits . If a Participant dies prior to commencement of benefits but on or after his or her Termination Date, the Employer shall pay a survivor benefit (paid in accordance with Section 4.3) to the Participant’s Beneficiary(ies) in an amount equal to the sum of (a) sixty-six and two thirds percent (66 2/3%) of the Actuarial Equivalent of the Early Termination Benefit calculated under Section 5.4, determined without offsets in Section 5.4.2, (b) less the death benefit paid, if any, determined in accordance with the Retirement Plan, and (c) less the death benefit paid, if any, determined in accordance with the Security Plan for Senior Management Employees I. Solely for purposes of this Section 4.2.1 Actuarial Equivalence will reduce the Early Termination Benefit from its usual commencement date to the first day of the month coincident or following the date of death, based on the age of the Participant and shall not take into consideration any illness or accident which has impacted the Participant’s individual life expectancy.

4.2.2 Death After Commencement of Benefits . If a Participant dies after commencement of benefits, a survivor benefit will be paid only if, and to the extent provided for, under the form of benefit elected by the Participant pursuant to Section 5.6.

4.3 Method of Payment . The amounts paid to a Participant’s beneficiaries under Sections 4.1 and 4.2.1 shall be according to the Participant’s election prior to or within thirty (30) days of initial eligibility for this Plan under Section 3.1 from among the following methods of payment:

4.3.1 Annuity/Term Benefit .

(a) Spouse . If payment is to the spouse of the Participant, this Plan shall provide a survivor annuity with monthly payments for the life of the spouse beginning generally on the first day of the month coincident with or following the date of death but in no event later than December 31 of the year following the year in which the date of death occurred or such other deadline as established by the Internal Revenue Code or applicable regulations; provided, however, if the spouse’s date of birth is more than ten (10) years after the Participant’s date of birth, the monthly benefit shall be reduced using the

Actuarial Equivalent factors to reflect the number of years over ten (10) the spouse is younger than the Participant.

(b) Other Beneficiary(ies) . If the payment is to the Participant’s Beneficiary (other than the Participant’s spouse), a survivor benefit payment amount shall be calculated assuming the Beneficiary is the same age as the Participant beginning generally on the first day of the month coincident with or following the date of death but in no event later than December 31 of the year following the year in which the date of death occurred or such other deadline as established by the Internal Revenue Code or applicable regulations. The survivor benefit payment shall be a monthly payment for a period beginning on the first day of the month coincident with or following the date of death of the Participant (“PTSB Term Beginning”) and ending on the last day of the month coincident with or following the earlier of (A) the date of death of the Participant’s Beneficiary or (B) the date that is the end of the normal life expectancy period of the Participant immediately before death (such life expectancy shall be based on the age of the Participant and shall not take into consideration any illness or accident which has impacted the Participant’s individual life expectancy) (“PTSB Term Ending”). If the Participant designates multiple beneficiaries for the benefit under this Section 4.3.1(b), the payment shall be allocated among the beneficiaries in accordance with Section 4.3.4 and each beneficiary shall be subject to a separate PTSB Term Ending for such beneficiary’s respective portion of the benefit

4.3.2 Lump Sum . A cash lump sum, payable as soon as practicable (generally within 90 days but in no event later than December 31 of the year following the year in which the date of death occurred or such other deadline as established by the Internal Revenue Code or applicable regulations) after the Participant’s death. The lump sum payment shall be the Actuarial Equivalent of the amount determined in Section 4.3.1.

4.3.3 Default Method . If the Participant fails to select in the election form the Method of Payment, or the benefit is to be paid to the estate of the Participant, the Participant shall be deemed to have elected a cash lump sum as described in Section 4.3.2.

4.3.4 Priority of Payments to Participant’s Beneficiaries . The amount payable on death of the Participant shall be paid to the Participant’s beneficiary(s) in the following order of priority:

(a) Designated Beneficiaries . The amount payable on death of the Participant shall be paid to the beneficiaries, and in such amounts, designated by the Participant on such form approved by the Administrative Committee. If the Participant is married, the Primary Beneficiary shall be the Participant’s spouse unless the Participant obtains the written consent from the Participant’s spouse to designate a Primary Beneficiary other than the Participant’s spouse. Each unmarried Participant shall have the right, at any time, to designate any person or persons as Beneficiary or Beneficiaries (both primary as well as contingent) to whom payment under this Plan shall be made in the event of the Participant’s death prior to the discharge of the Employer’s obligation under this Plan. Any Beneficiary designation may be changed by a Participant by the filing of a written form prescribed by the Administrative Committee. The filing of a new Beneficiary designation form will cancel all Beneficiary

designations previously filed. Any finalized divorce or marriage of a Participant subsequent to the date of filing of a Beneficiary designation form shall automatically revoke the prior designation.

(b) Spouse . If the Participant fails to designate beneficiaries in writing to the Administrator, or if a previous Beneficiary designation is revoked by marriage, or if the designated beneficiaries fail to survive the Participant, then to the Participant’s spouse.

(c) Children . If the Participant fails to designate beneficiaries in writing to the Administrator or if the designated beneficiaries and the Participant’s spouse fail to survive the Participant, then to the Participant’s children in equal shares, except that if any child predeceases the Participant but leaves issue surviving, the issue shall take by right of representation.

(d) Estate . If the Participant fails to designate beneficiaries in writing to the Administrator, or if the designated beneficiaries and the Participant’s spouse and Participant’s issue fail to survive the Participant, then to the Participant’s estate.

4.3.5 Subsequent Method of Payment Elections . If a Participant submits an election form to modify the Method of Payment previously selected, the new election form shall take effect no earlier than 12 months after the date such form is received and approved by the Administrator (i.e., if a distribution event occurs within 12 months of having chosen the new Method of Payment, distribution shall be made in accordance with the previous Method of Payment selected.)

4.4 Effect of Payment . The payment to the Beneficiary(ies) shall completely discharge the Employer’s obligations under this Plan.

4.5 Appendix A - Example Calculations . The example calculations set forth in Appendix A to this Plan are hereby incorporated by reference into this Plan and shall inform the interpretation of calculations performed pursuant to this Article IV.

ARTICLE V

SECURITY PLAN RETIREMENT BENEFITS

5.1 Normal Retirement Benefit . If a Participant’s Separation from Service occurs at a Normal Retirement Date, the Employer shall pay to the Participant a monthly Security Plan Retirement Benefit beginning the first day of the month following the Normal Retirement Date. Payment of this benefit cannot be deferred. The monthly Security Plan Retirement Benefit shall equal the Target Retirement Percentage multiplied by the Participant’s Final Average Monthly Compensation, less

5.1.1 the Participant’s retirement benefit, if any, under the Retirement Plan, assuming such retirement benefit were paid as a single life annuity commencing when payments commence under this Plan (regardless of the form of benefit actually selected by the Participant and regardless of when benefits actually commence under the Retirement Plan)

5.1.2 the Participant’s retirement benefit (before any adjustment due to an accelerated distribution pursuant to Section 7.4 thereof), if any, under the Security Plan for Senior Management Employees I, assuming such retirement benefit were paid as a single life annuity commencing when payments commence under this Plan (regardless of the form of benefit actually selected by the Participant and regardless of when benefits actually commence under the Security Plan for Senior Management Employees I).

5.2 Early Retirement Benefit . If a Participant’s Separation from Service occurs on or after an Early Retirement Date, the Employer shall pay to the Participant a monthly Security Plan Retirement Benefit beginning the first day of the month following the Early Retirement Date. Payment of this benefit cannot be deferred. The monthly Security Plan Retirement Benefit shall be equal to the Target Retirement Percentage, multiplied by the Early Retirement Factor and by the Participant’s Final Average Monthly Compensation, less

5.2.1 the Participant’s retirement benefit, if any, under the Retirement Plan, assuming such retirement benefit were paid as a single life annuity commencing when payments commence under this Plan (regardless of the form of benefit actually selected by the Participant and regardless of when benefits actually commence under the Retirement Plan) and

5.2.2 the Participant’s retirement benefit (before any adjustment due to an accelerated distribution pursuant to Section 7.4 thereof), if any, under the Security Plan for Senior Management Employees I, assuming such retirement benefit were paid as a single life annuity commencing when payments commence under this Plan (regardless of the form of benefit actually selected by the Participant and regardless of when benefits actually commence under the Security Plan for Senior Management Employees I).

5.3 Early Retirement Factor . If a Participant’s Separation from Service occurs before the Participant's Normal Retirement Date, the Target Retirement Percentage shall be multiplied by one (1) of the following Early Retirement Factors.



Exact Age When Payments Begin	Early Retirement Factor
62	100%
61	96%
60	92%
59	87%
58	82%
57	77%
56	72%
55	67%
54	62%
53	57%



52	52%
51	47%
50	42%
49	38%
48	34%

Early Retirement Factors will be prorated to reflect retirement based on completed months rather than exact age.

5.4 Early Termination Benefits . If a Participant's Separation from Service occurs prior to his or her death, prior to his or her Early Retirement Date, and not within a Change in Control Period, the Employer shall pay to the Participant, commencing on the first day of the month following the Participant's fifty-fifth (55 ^th ) birthday, the Security Plan Retirement Benefit as determined under this section. Payment of this benefit cannot be deferred.

5.4.1 The Target Retirement Percentage shall be calculated based upon the Participant's Years of Participation and then multiplied by a fraction equal to the Participant's Years of Participation divided by the Years of Participation the Participant would have had at the Normal Retirement Date if the Participant had continued to be employed by the Employer to age sixty-two (62). The adjusted Target Retirement Percentage shall be multiplied by the factor described in Section 5.3 for each month between the Participant's benefits commencement date (age 55) and age sixty-two (62).

5.4.2 The Early Termination Benefit shall be reduced by

(a) the Participant's retirement benefit, if any, under the Retirement Plan, assuming such retirement benefit were paid as a single life annuity commencing when payments commence under this Plan (regardless of the form of benefit actually selected by the Participant and regardless of when benefits actually commence under the Retirement Plan) and

(b) the Participant's retirement benefit (before any adjustment due to an accelerated distribution pursuant to Section 7.4 thereof), if any, under the Security Plan for Senior Management Employees I, assuming such retirement benefit were paid as a single life annuity commencing when payments commence under this Plan (regardless of the form of benefit actually selected by the Participant and regardless of when benefits actually commence under the Security Plan for Senior Management Employees I).

5.5 Separation from Service After Change in Control . If a Participant's Separation from Service occurs within the Change in Control Period prior to his or her Normal Retirement Date, the Participant shall receive the Early Retirement Benefit calculated with the Early Retirement Factors set forth in 5.3. If the Separation from Service occurs on or after an Early Retirement Date, the Early Retirement Benefit shall commence on the first day of the month following the Early Retirement Date. If the Separation from Service occurs prior to an Early Retirement Date, the Early Retirement Benefit shall

commence on the first day of the month following the Participant’s fifty-fifth (55 ^th ) birthday. Payment of this benefit cannot be deferred.

5.6 Form of Payment . The Security Plan Retirement Benefit shall be paid as a single life annuity for the lifetime of the Participant.

5.6.1 The Participant may also elect to receive Actuarial Equivalent payments in one of the forms of benefit listed below:

(a) A joint and survivor annuity with monthly payments continued to the surviving spouse at an amount equal to 75% of the Participant’s benefit; provided, however, if the spouse’s date of birth is more than ten (10) years after the Participant's date of birth, the monthly benefit shall be reduced using the Actuarial Equivalent factors to reflect the number of years over ten (10) the spouse is younger than the Participant.

(b) A joint and survivor annuity with monthly payments continued to the surviving spouse at an amount equal to the Participant's benefit; provided, however, if the spouse’s date of birth is more than ten (10) years after the Participant's date of birth, the monthly benefit shall be reduced using the Actuarial Equivalent factors to reflect the number of years over ten (10) the spouse is younger than the Participant.

(c) A single life annuity, if the Participant had previously elected one of the joint and survivor annuity options listed above.

5.6.2 If the Actuarial Equivalent of the Security Plan Retirement Benefit is less than the then applicable dollar amount under Section 402(g)(1)(B) of the Code, the Administrative Committee may direct that the Participant’s benefit be paid as a lump sum as soon as practicable (but in all events within 90 days) after the Participant’s Termination Date.

5.6.3 The election to receive benefits in a different form of payment may be made at any time prior to commencement of payment.

5.7 Code Section 162(m) Delay . If the Administrative Committee reasonably anticipates that the Company’s deduction with respect to a payment would be limited or eliminated by application of Code Section 162(m) if the payment were made as scheduled, the Administrative Committee may unilaterally delay the time of the making or commencement of payment, provided such payment will be made either during the first year in which the Administrative Committee reasonably anticipates (or should reasonably anticipate) that if the payment is made during such year the deduction of the payment will not be barred by application of Code Section 162(m) or during the period beginning with the date of the Participant’s Separation from Service and ending on the later of the last day of the Company’s tax year in which the Separation from Service occurs or the 15 ^th day of the third month following the date of the Separation from Service; provided, further, that the provisions of this Section 5.7 shall be applied in accordance with the rules relating to delay of payments subject to Code Section 162(m) as contained in

Treasury Regulation Section 1.409A-2(b)(7)(i). No election may be provided to the Participant with respect to the timing of a payment pursuant to this Section 5.7.

5.8 Payment to Specified Employees . Notwithstanding anything to the contrary contained herein, if a Participant is deemed on his or her Termination Date to be a “specified employee” (as that term is used in Code Section 409A(a)(2)(B)), as determined under the Company’s policy for determining specified employees, no payments shall be made under this Plan due to the Participant’s Separation from Service before the date that is 6 months following the Participant’s Separation from Service or, if earlier, the date of the Participant’s death, and any amounts accumulated during such period shall be paid in a lump sum payment to the Participant on the first business day following the date that is six months after the Participant’s Separation from Service or, if the Participant dies during such six month period, to the Participant’s Beneficiary within 60 days after the date of the Participant’s death. Any remaining payments and benefits due under this Plan shall be paid or provided in accordance with the normal payment dates specified for them herein.

ARTICLE VI

OTHER RETIREMENT PROVISIONS

6.1 Disability . During a period of Disability that begins prior to January 1, 2014, a Participant will continue to accrue Years of Participation, and Compensation shall be credited to a Participant who is receiving Disability benefits at the full-time equivalent rate of pay that was being earned immediately prior to becoming disabled. No Years of Participation shall be accrued and no Compensation shall be credited during a period of Disability which begins on or after January 1, 2014.

6.2 Withholding Payroll Taxes . The Employer shall withhold from payments made hereunder any taxes required to be withheld from a Participant’s wages under federal, state or local law.

6.3 Payment to Guardian\Conservator . If a Plan benefit is payable to a minor or a person declared incompetent or to a person incapable of handling the disposition of property, the Administrative Committee may direct payment of such Plan benefit to the guardian, conservator, legal representative or person having the care and custody of the minor, incompetent or incapable person. The Administrative Committee may require proof of incompetency, minority, incapacity, guardianship, or conservatorship, as it may deem appropriate, prior to distribution of this Plan benefit. The distribution shall completely discharge the Administrative Committee and the Employer from all liability with respect to such benefit.

ARTICLE VII

ADMINISTRATION

7.1 Administrative Committee Duties . This Plan shall be administered by an Administrative Committee, which shall be the Chief Executive Officer of the Company and the Fiduciary Committee appointed by the Compensation Committee. Members of the Administrative Committee may be Participants under this Plan. The Administrative Committee shall have the authority to make, amend,

interpret and enforce all appropriate rules and regulations for the administration of this Plan and decide or resolve any and all questions including interpretations of this Plan, as may arise in connection with this Plan. A majority vote of the Administrative Committee members shall control any decision.

In the administration of this Plan, the Administrative Committee may, from time to time, employ agents and delegate to them such administrative duties as it sees fit and may from time to time consult with counsel who may be counsel to the Employer.

Subject to Article IX, the decision or action of the Administrative Committee in respect of any questions arising out of, or in connection with, the administration, interpretation and application of this Plan and the rules and regulations promulgated hereunder shall be final and conclusive and binding upon all persons having any interest in this Plan.

7.2 Indemnity of Administrative Committee . To the extent permitted by applicable law, the Employer shall indemnify, hold harmless and defend the Administrative Committee against any and all claims, loss, damage, expense or liability arising from any action or failure to act with respect to this Plan, provided that the Administrative Committee was acting in accordance with the applicable standard of care. The indemnity provisions set forth in this Article shall not be deemed to restrict or diminish in any way any other indemnity available to the Administrative Committee members in accordance with the Articles or By-laws of the Company.

ARTICLE VIII

CLAIMS PROCEDURE

8.1 Claim . Any person claiming a benefit, requesting an interpretation or ruling under this Plan, or requesting information under this Plan shall present the request in writing to the Administrative Committee who shall respond in writing as soon as practicable.

8.2 Denial of Claim . If the claim or request is denied, the written notice of denial shall state:

8.2.1 the reason for denial, with specific reference to this Plan provisions where applicable on which the denial is based;

8.2.2 a description of any additional material or information required and an explanation of why it is necessary; and

8.2.3 an explanation of this Plan’s claims review procedure.

8.3 Review of Claim . Any person whose claim or request is denied or who has not received a response within thirty (30) days may request a review by notice given in writing to the Administrative Committee. The claim or request shall be reviewed by the Administrative Committee who may, but shall not be required to, grant the claimant a hearing. On review, the claimant may have representation, examine pertinent documents, and submit issues and comments in writing.

8.4 Final Decision . The decision on review shall normally be made within sixty (60) days. If an extension of time is required for a hearing or other special circumstances, the claimant shall be notified and the time limit shall be one hundred twenty (120) days. The decision shall be in writing and shall state the reason and any relevant Plan provisions. All decisions on review shall be final and bind all parties concerned.

ARTICLE IX

TERMINATION, SUSPENSION OR AMENDMENT

9.1 Termination, Suspension or Amendment of Plan . The Board may, in its sole discretion, terminate or suspend this Plan at any time or from time to time, in whole or in part. The Compensation Committee may amend this Plan at any time or from time to time. Any amendment may provide different benefits or amounts of benefits from those herein set forth. However, no such termination, suspension or amendment or other action with respect to this Plan shall adversely affect the benefits of Participants which have accrued prior to such action, the benefits of any Participant who has previously retired, or the benefits of any Beneficiary of a Participant who has previously died.

9.2 Change in Control . Notwithstanding Section 9.1 above, during a Change in Control Period, neither the Board nor the Administrative Committee may terminate this Plan with regard to accrued benefits of current Participants. No amendment may be made to this Plan during a Change in Control Period which would adversely affect the accrued benefits of current Participants, the benefits of any Participant who has retired, or the Beneficiary of any Participant who has died. This Plan shall continue to operate and be effective with regard to all current or retired Participants and their Beneficiaries during any Change in Control Period.

ARTICLE X

MISCELLANEOUS

10.1 Unfunded Plan . This Plan is intended to be an unfunded plan maintained primarily to provide deferred compensation benefits for a select group of "management or highly compensated employees" within the meaning of Sections 201, 301 and 401 of the Employee Retirement Income Security Act of 1974, as amended ("ERISA"), and therefore to be exempt from the provisions of Parts 2, 3 and 4 of Title I of ERISA.

10.2 Unsecured General Creditor . Participants and their Beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interest or claims in any property or asset of the Employer, nor shall they be Beneficiaries of, or have any rights, claims or interests in any life insurance policies, annuity contracts or the proceeds therefrom owned or which may be acquired by the Employer. Except as may be provided in Section 10.3, such policies, annuity contracts or other assets of the Employer shall not be held under any trust for the benefit of Participants, their Beneficiaries, heirs, successors or assigns, or held in any way as collateral security for the fulfilling of the obligation of the Employer under this Plan. Any and all of the Employer’s assets and policies shall be, and remain, the general, unpledged,

unrestricted assets of the Employer. The Employer’s obligation under this Plan shall be that of an unfunded and unsecured promise to pay money in the future.

10.3 Trust Fund . The Employer shall be responsible for the payment of all benefits provided under this Plan. At its discretion, the Employer may establish one or more trusts, with such trustees as the Board may approve, for the purpose of providing for the payment of such benefits. Such trust or trusts may be irrevocable, but the assets thereof shall be subject to the claims of the Employer’s creditors. To the extent any benefits provided under this Plan are actually paid from any such trust, the Employer shall have no further obligation with respect thereto, but to the extent not so paid, such benefits shall remain the obligation of, and shall be paid by, the Employer.

10.4 Nonassignability . Neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate or convey in advance of actual receipt the amounts, if any, payable hereunder, or any part thereof, which are, and all rights to which are, expressly declared to be unassignable and nontransferable. No part of the amount payable shall, prior to actual payment, be subject to seizure or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person, nor be transferable by operation of law in the event of Participant’s or any other person’s bankruptcy or insolvency.

10.5 Not a Contract of Employment . The terms and conditions of this Plan shall not be deemed to constitute a contract of employment between the Employer and the Participant, and the Participant (or Participant’s Beneficiary) shall have no rights against the Employer except as may otherwise be specifically provided herein. Moreover, nothing in this Plan shall be deemed to give a Participant the right to be retained in the service of the Employer or to interfere with the right of the Employer to discipline or discharge the Participant at any time.

10.6 Governing Law . The provisions of this Plan shall be construed, interpreted and governed in all respects in accordance with the applicable federal law and, to the extent not preempted by such federal law, in accordance with the laws of the State of Idaho without regard to the principles of conflicts of laws.

10.7 Validity . If any provision of this Plan shall be held illegal or invalid for any reason, the remaining provisions shall nevertheless continue in full force and effect without being impaired or invalidated in any way.

10.8 Notice . Any notice or filing required or permitted to be given under this Plan shall be sufficient if in writing and hand delivered, or sent by registered or certified mail or fax. The notice shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification.

10.9 Successors . Subject to Section 9.1, the provisions of this Plan shall bind and inure to the benefit of the Employer and its successors and assigns. The term successors as used herein shall include any corporate or other business entity which shall, whether by merger, consolidation, purchase or

otherwise acquire all or substantially all of the business and assets of the Employer, and successors of any such corporation or other business entity.

IDAHO POWER COMPANY

By: /s/ Lonnie Krawl

Lonnie Krawl, SVP of Administrative

Services & Chief Human Resources Officer

By: /s/ Patrick Harrington

Patrick Harrington, Corporate Secretary

Appendix A

Example Calculations



Idaho Power Company
SMSP II Section 4.1 and 4.2.1 Survivor Benefit Examples
	EXAMPLE 1	EXAMPLE 2	EXAMPLE 3	EXAMPLE 4
	Participant not eligible	Participant eligible for
	for Early Retirement,	Early Retirement,	Participant not eligible	Participant eligible
	Non-spouse	Non-spouse	for Early Retirement,	for Early Retirement,
	beneficiary or Spouse	beneficiary or Spouse	Spouse is 11 years	Spouse is 20 years
	is no more than 10	is no more than 10	younger	younger
	years younger	years younger
Participant Age:	45	60	45	55
Spouse Age:	42	56	34	35
Years of Participation	15	20	25	30
Years of Participation at NRD (age 62)	32	22	42	37
1. Annual Accrued Benefit:
A. Qualified Plan	$30,000.00	$70,000.00	$50,000.00	$60,000.00
B. Security Plan I	$0.00	$0.00	$0.00	$0.00
C. Security Plan II Accrued Benefit at Date of Death	$190,000.00	$400,000.00	$310,000.00	$420,000.00
D. Total Accrued Pension Benefits at Date of Death	$220,000.00	$470,000.00	$360,000.00	$480,000.00
E. Security Plan II Accrued Benefit Assuming Service to Age 62 *	$219,000.00	$410,000.00	$310,000.00	$420,000.00
F. Total Accrued Pension Benefits with SMSP II Using Service to Age 62 (1.A + 1.B + 1.E)	$249,000.00	$480,000.00	$360,000.00	$480,000.00
2. Section 4.1.1 Pre-termination Survivor Benefit
A. Gross SMSP Accrued Benefit Before Offsets (1 .F)	$249,000.00	$480,000.00	$360,000.00	$480,000.00
B. 2/3 Gross SMSP Accrued Benefit Before Offsets	$166,000.00	$320,000.00	$240,000.00	$320,000.00
C. 100% J&S Factor (no reduction unless spouse is more than 10 years younger)	1.00000	1.00000	0.98987	0.89873
D. 1/2 Qualified Accrued Benefit (l.A divided by 2)	$15,000.00	$35,000.00	$25,000.00	$30,000.00
E. SMSP I Death Benefit	$0.00	$0.00	$0.00	$0.00
F. SMSP II 4.1.1 Survivor Benefit (2.B multiplied by 2.C, minus 2.D, minus 2.E) **	$151,000.00	$285,000.00	$212,568.80	$257,593.60

3. Section 4.1.2 Pre-termination Survivor Benefit

(if death occurs after eligibility for Early Retirement)



A.	Gross SMSP Accrued Benefit Before Offsets (1.D)	N/A	$470,000.00	N/A	$480,000.00
B.	Early Retirement Factor (ERF)	N/A	0.92000	N/A	0.67000
C.	100% J&S Factor (reduced from 0.79 if spouse is more than 10 years younger)	N/A	0.79000	N/A	0.71000
D.	1/2 Qualified Accrued Benefit(1.A divided by 2)	N/A	$35,000.00	N/A	$30,000.00
E.	SMSP I Death Benefit	N/A	$0.00	N/A	$0.00
F.	SMSP II 4.1.2 Survivor Benefit multiplied by 3.B multiplied by 3.C, minus 3.D, minus 3.E)	N/A	$306,596.00	N/A	$198,336.00



4. Section 4.1 Pre-termination Survivor Benefit (maximum of 2.F and 3.F)**		$151,000.00	$306,596.00	$212,568.80	$257,593.60
Section 4.2.1 Post-termination Survivor Benefit (Participant dies prior to commencement of benefits but on or after his or her Termination Date)
A.	Gross SMSP Accrued Benefit Before Offsets (1 .D)	$220,000	N/A	$360,000.00	N/A
B.	Service Proration Factor for Early Termination Benefit	0.4688	N/A	0.5952	N/A
C.	ERF for Early Termination Benefit at age 55	0.6700	N/A	0.6700	N/A
D.	5.4 Early Termination Benefit Prior to Offsets (5.A * 5.B * 5.C)	$69,101.12	N/A	$143,562.24	N/A
E.	Actuarial Equivalent Factor from Age 55 to Current Age	0.40555	N/A	0.40555	N/A
F.	100% J&S Factor	1.00000	N/A	0.98987	N/A
G	(no reduction unless spouse is more than 10 years younger) 2/3 Gross Early Termination Benefit Before Offsets	$18,682.64	N/A	$38,421.25	N/A
	(5.D * 5.E * 5.F * 2/3)
H	1/2 Qualified Accrued Benefit (l.A divided by 2)	$15,000.00	N/A	$25,000.00	N/A
I.	SMSP I Death Benefit	$0.00	N/A	$0.00	N/A
J.	SMSP II 4.2.1 Death Benefit (5.G minus 5.H, minus 5.1)**	$3,682.64	N/A	$13,421.25	N/A

*The actual calculation of the SMSP II benefit using service to age 62 should reflect the change to the Target Retirement Percentage formula as of December 31, 2017, if applicable.

**The amounts displayed above for the SMSP II benefit assume the qualified pension plan benefit has commenced. The SMSP II benefit will be higher (by the amount of the qualified plan benefit) until the qualified plan benefit commences. The SMSP II benefit cannot be less than zero.

The examples above use Retirement P/an Actuarial Equivalence factors from Appendix II (for items 2. C., 3. C. and 5.F.) and Section 1.02(a) (for item 5.E.). The Administrative Committee reserves the right to amend the basis for Actuarial Equivalence pursuant to Section 2.1 of the Plan.

The examples shown were provided by Milliman, use hypothetical accrued benefits under the three plans, and should not be relied on for any purpose other than to demonstrate the procedure for calculating the SMSP II survivor benefits under section 4.1 and 4.2.1. Used with permission from Milliman.

Exhibit 10.40

IDACORP, Inc. and/or Idaho Power Company Executive Officers

with Amended and Restated Change in Control Agreements

(as of February 8, 2017)



Name	Title	Date of Agreement
Darrel T. Anderson	President and Chief Executive Officer of IDACORP, Inc. and Idaho Power Company	12/23/2008
Brian R. Buckham*	Vice President and General Counsel of IDACORP, Inc. and Idaho Power Company	4/4/2016
Lisa A. Grow	Senior Vice President of Operations of Idaho Power Company	12/12/2008
Steven R. Keen	Senior Vice President, Chief Financial Officer, and Treasurer of IDACORP, Inc. and Idaho Power Company	12/30/2008
Lonnie Krawl*	Senior Vice President of Administrative Services and Chief Human Resources Officer of Idaho Power Company	9/30/2013
Jeffrey L. Malmen*	Senior Vice President of Public Affairs of IDACORP, Inc. and Idaho Power Company	12/8/2008
Tessia Park*	Vice President of Power Supply of Idaho Power Company	1/5/2016
Kenneth W. Petersen*	Vice President, Controller, and Chief Accounting Officer of IDACORP, Inc. and Idaho Power Company	5/20/2010
N. Vern Porter*	Vice President of Customer Operations of Idaho Power Company	3/18/2010
Adam Richins*	General Manager of Customer Operations, Engineering & Construction of Idaho Power Company (Vice President of Customer Operations and Business Development of Idaho Power Company effective March 1, 2017)	2/8/2017

*Change in control agreement does not include 13 ^th -month trigger or tax gross-up provisions.

Exhibit 10.41

IDACORP, Inc.

2000 Long-Term Incentive and Compensation Plan

Plan Document and Additional Information

This document constitutes part of a prospectus covering securities that have been registered under the Securities Act of 1933.

PLAN DOCUMENT

IDACORP, INC .

2000 LONG-TERM INCENTIVE AND COMPENSATION PLAN

Article 1. Establishment, Purpose and Duration

1.1 Establishment of the Plan. IDACORP, Inc., an Idaho corporation (hereinafter referred to as the "Company"), hereby establishes an incentive and compensation plan for officers, key employees and directors, to be known as the "IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan" (hereinafter referred to as the "Plan"), as set forth in this document. The Plan permits the grant of nonqualified stock options (“NQSO”), incentive stock options (“ISO”), stock appreciation rights (“SAR”), restricted stock, restricted stock units, performance units, performance shares and other awards.

The Plan became effective when approved by the shareholders at the 2000 Annual Meeting of Shareholders (the "Effective Date") and shall remain in effect as provided in Section 1.3 herein, as amended from time to time.

1.2 Purpose of the Plan. The purpose of the Plan is to promote the success and enhance the value of the Company by linking the personal interests of Participants to those of Company shareholders and customers.

The Plan is further intended to provide flexibility to the Company in its ability to motivate, attract and retain the services of Participants upon whose judgment, interest and special effort the successful conduct of its operations is largely dependent.

1.3 Duration of the Plan. The Plan shall commence on the Effective Date, as described in Section 1.1 herein, and shall remain in effect, subject to the right of the Board of Directors to terminate the Plan at any time pursuant to Article 14 herein, until all Shares subject to it shall have been purchased or acquired according to the Plan's provisions.

Article 2. Definitions

Whenever used in the Plan, the following terms shall have the meanings set forth below and, when such meaning is intended, the initial letter of the word is capitalized:

2.1 Award means, individually or collectively, a grant under the Plan of NQSOs, ISOs, SARs, Restricted Stock, Restricted Stock Units, Performance Units, Performance Shares or any other type of award permitted under Article 10 of the Plan.

2.2 Award Agreement means an agreement entered into by each Participant and the Company, setting forth the terms and provisions applicable to an Award granted to a Participant under the Plan.

2.3 Base Value of an SAR shall have the meaning set forth in Section 7.1 herein.

2.4 Board or Board of Directors means the Board of Directors of the Company.

2.5 Change in Control means the earliest of the following to occur:

(a) any Person, excluding (i) the Company or any Subsidiary, (ii) a corporation or other entity owned, directly or indirectly, by the shareholders of the Company immediately prior to the transaction in substantially the same proportions as their ownership of stock of the Company, (iii) an employee benefit plan (or related trust) sponsored or maintained by the Company or any Subsidiary or (iv) an underwriter temporarily holding securities pursuant to an offering of such securities ("Change in Control Person") is the beneficial owner (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of 20% or more of the combined voting power of the then outstanding voting securities eligible to vote generally in the election of directors of the Company; provided, however, that no Change in Control will be deemed to have occurred as a result of a change in ownership percentage resulting solely from an acquisition of securities by the Company;

(b) consummation of a merger, consolidation, reorganization or share exchange, or sale of all or substantially all of the assets, of the Company or Idaho Power Company (a "Qualifying Transaction"), unless, immediately following such Qualifying Transaction, all of the following have occurred: (i) all or substantially all of the beneficial owners of the Company immediately prior to such Qualifying Transaction beneficially own in substantially the same proportions, directly or indirectly, more than 50% of the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors of the corporation or other entity resulting from such Qualifying Transaction (including, without limitation, a corporation or other entity which, as a result of such transaction, owns the Company or all or substantially all of the Company's assets either directly or through one or more subsidiaries) (as the case may be, the "Successor Entity"), (ii) no Change in Control Person is the beneficial owner (as defined in Rule 13d-3 under the 1934 Act), directly or indirectly, of 20% or more of the combined voting power of the then outstanding voting securities eligible to vote generally in the election of directors of the Successor Entity and (iii) at least a majority of the members of the board of directors of the Successor Entity are Incumbent Directors;

(d) within a 24-month period, individuals who were directors of the Board immediately before such period ("Incumbent Directors") cease to constitute at least a majority of the directors of the Board; provided, however, that any director who was not a director of the Board at the beginning of such period shall be deemed to be an Incumbent Director if the election or nomination for election of such director was approved by the vote of at least two-thirds of the directors of the Board then still in office (i) who were in office at the beginning of the 24-month period or (ii) whose election or nomination for election was so approved, in each case, unless such individual was elected or nominated as a result of an actual or threatened election contest or as a result of an actual or threatened solicitation of proxies or consents by or on behalf of any Change in Control Person other than the Board.

For avoidance of doubt, transactions for the purpose of dividing Idaho Power Company's assets into separate distribution, transmission or generation entities or such other entities as the Company or Idaho Power Company may determine shall not constitute a Change in Control unless so determined by the Board.

2.6 Code means the Internal Revenue Code of 1986, as amended from time to time.

2.7 Committee means the committee, as specified in Article 3, appointed by the Board to administer the Plan with respect to Awards.

2.8 Company means IDACORP, Inc., an Idaho corporation, or any successor thereto as provided in Article 16 herein.

2.9 Covered Employee means any Participant who would be considered a "covered employee" for purposes of Section 162(m) of the Code.

2.10 Director means any individual who is a member of the Board of Directors of the Company.

2.11 Disability means the continuous inability of an Employee because of illness or injury to engage in any occupation or employment for wage or profit with the Company or any other employer (including self-employment) for which he is reasonably qualified by education, training or experience. An Employee will not be considered disabled during any period unless he is under the regular care and attendance of a duly qualified physician.

2.12 Dividend Equivalent means, with respect to Shares subject to an Award, a right to be paid an amount equal to dividends declared on an equal number of outstanding Shares.

2.13 Eligible Person means an individual who is eligible to participate in the Plan, as set forth in Section 5.1 herein.

2.14 Employee means an individual who is paid on the payroll of the Company or of the Company's Subsidiaries, who is not covered by any collective bargaining agreement to which the Company or any of its Subsidiaries is a party, and is classified in the payroll system as a regular full-time, part-time or temporary employee. For purposes of the Plan, transfer of employment of a Participant between the Company and any one of its Subsidiaries (or between Subsidiaries) shall not be deemed a termination of employment.

2.15 Exchange Act means the Securities Exchange Act of 1934, as amended from time to time, or any successor act thereto.

2.16 Exercise Period means the period during which an SAR or Option is exercisable, as set forth in the related Award Agreement.

2.17 Fair Market Value means the fair market value of a Share as determined in good faith by the Committee or pursuant to a procedure specified in good faith by the Committee; provided, however, that if the Committee has not specified otherwise, Fair Market Value shall mean the closing price of a Share as reported in the consolidated transaction reporting system, or, if there was no such sale on the relevant date, then on the last previous day on which a sale was reported.

2.18 Freestanding SAR means an SAR that is not a Tandem SAR.

2.19 Incentive Stock Option or ISO means an option to purchase Shares, granted under Article 6 herein, which is designated as an Incentive Stock Option and satisfies the requirements of Section 422 of the Code.

2.20 Nonqualified Stock Option or NQSO means an option to purchase Shares, granted under Article 6 herein, which is not intended to be an Incentive Stock Option under Section 422 of the Code.

2.21 Option means an Incentive Stock Option or a Nonqualified Stock Option.

2.22 Option Exercise Price means the price at which a Share may be purchased by a Participant pursuant to an Option, as determined by the Committee and set forth in the Option Award Agreement.

2.23 Participant means an Eligible Person who has outstanding an Award granted under the Plan.

2.24 Performance Goals means the performance goals established by the Committee, which shall be based on one or more of the following measures: sales or revenues, earnings per share, shareholder return and/or value, funds from operations, operating income, gross income, net income, cash flow, return on equity, return on capital, earnings before interest, operating ratios, stock price, customer satisfaction, accomplishment of mergers, acquisitions, dispositions or similar extraordinary business transactions, profit returns and margins, financial return ratios, budget achievement, performance against budget, and/or market performance. Performance goals may be measured solely on a corporate, subsidiary or business unit basis, or a combination thereof. Performance goals may reflect absolute entity performance or a relative comparison of entity performance to the performance of a peer group of entities or other external measure.

2.25 Performance Period means the time period during which Performance Unit/Performance Share Performance Goals must be met.

2.26 Performance Share means an Award described in Article 9 herein.

2.27 Performance Unit means an Award described in Article 9 herein.

2.28 Period of Restriction means the period during which the transfer of Restricted Stock or Restricted Stock Units is limited in some way, as provided in Article 8 herein.

2.29 Person shall have the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act, as used in Sections 13(d) and 14(d) thereof, including usage in the definition of a "group" in Section 13(d) thereof.

2.30 Plan means the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended from time to time.

2.31 Qualified Restricted Stock means an Award of Restricted Stock designated as Qualified Restricted Stock by the Committee at the time of grant and intended to qualify for the exemption from the limitation on deductibility imposed by Section 162(m) of the Code that is set forth in Section 162(m)(4)(C).

2.32 Qualified Restricted Stock Unit means an Award of Restricted Stock Units designated as Qualified Restricted Stock Units by the Committee at the time of grant and intended to qualify for the exemption from the limitation on deductibility imposed by Section 162(m) of the Code that is set forth in Section 162(m)(4)(C).

2.33 Restricted Stock means an Award described in Article 8 herein.

2.34 Restricted Stock Unit means an Award described in Article 8 herein.

2.35 Retirement means a Participant's Separation from Service if (i) the Participant is age 55 or older at the time of the Separation from Service and (ii) the Committee determines that the Separation from Service constitutes Retirement for purposes of the Participant's Award.

2.36 Securities Act means the Securities Act of 1933, as amended.

2.37 Separation from Service means "separation from service" as that term is used in Section 409A(a)(2)(A)(i) of the Code.

2.38 Shares means the shares of common stock, no par value, of the Company.

2.39 Stock Appreciation Right or SAR means a right, granted alone or in connection with a related Option, designated as an SAR, to receive a payment on the day the right is exercised, pursuant to the terms of Article 7 herein. Each SAR shall be denominated in terms of one Share.

2.40 Subsidiary means any corporation (other than the Company) in an unbroken chain of corporations beginning with the Company if each of the corporations other than the last corporation in the unbroken chain owns stock possessing 50 percent or more of the total combined voting power of all classes of stock in one of the other corporations in such chain.

2.41 Tandem SAR means an SAR that is granted in connection with a related Option, the exercise of which shall require forfeiture of the right to purchase a Share under the related Option (and when a Share is purchased under the Option, the Tandem SAR shall be similarly canceled).

Article 3. Administration

3.1 The Committee . The Plan shall be administered by the Compensation Committee or such other committee (the "Committee") as the Board of Directors shall select consisting solely of two or more members of the Board. The members of the Committee shall be appointed from time to time by, and shall serve at the discretion of, the Board of Directors.

3.2 Authority of the Committee . The Committee shall have full power except as limited by law, the Articles of Incorporation or the Bylaws of the Company, subject to such other restricting limitations or directions as may be imposed by the Board and subject to the provisions herein, to determine the Eligible Persons to receive Awards; to determine the size and types of Awards; to determine the terms and conditions of such Awards; to construe and interpret the Plan and any agreement or instrument entered into under the Plan; to establish, amend or waive rules and regulations for the Plan's administration; and (subject to the provisions of Article 14 herein) to amend the terms and conditions of any outstanding Award. Further, the Committee shall make all other determinations which may be necessary or advisable for the administration of the Plan. As permitted by law, the Committee may delegate its authorities as identified hereunder.

3.3 Restrictions on Distribution of Shares and Share Transferability . Notwithstanding any other provision of the Plan, the Company shall have no liability to deliver any Shares or benefits under the Plan unless such delivery would comply with all applicable laws (including, without limitation, the Securities Act) and applicable requirements of any securities exchange or similar entity and unless the Participant's tax obligations have been satisfied as set forth in Article 15. The Committee may impose such restrictions on any Shares acquired pursuant to Awards under the Plan as it may deem advisable, including, without limitation, restrictions to comply with applicable Federal securities laws, with the requirements of any stock exchange or market upon which such Shares are then listed and/or traded and with any blue sky or state securities laws applicable to such Shares.

3.4 Decisions Binding . All determinations and decisions (including, without limitation, all interpretations) made by the Committee pursuant to the provisions of the Plan and all related orders or resolutions of the Board shall be final, conclusive and binding on all persons, including the Company, its shareholders, Eligible Persons, Employees, Participants and their estates and beneficiaries.

3.5 Costs. The Company shall pay all costs of administration of the Plan.

Article 4. Shares Subject to the Plan

4.1 Number of Shares. Subject to Section 4.2 herein, the maximum number of Shares available for grant under the Plan shall be 3,100,000. Shares underlying lapsed or forfeited Awards, or Awards that are not paid in Shares, may be reused for other Awards; provided, however, that the following Shares shall not be added to Shares available for grant under the Plan: (i) Shares that were subject to a stock-settled Stock Appreciation Right and were not issued upon the net settlement or net exercise of such Stock Appreciation Right, (ii) Shares tendered to the Company to pay the exercise price of an Option or (iii) Shares tendered to or withheld by the Company to pay the withholding taxes with respect to an Award. Shares granted pursuant to the Plan may be (i) authorized but unissued Shares of common stock, (ii) treasury shares or (iii) Shares purchased on the open market.

4.2 Adjustments in Authorized Shares and Awards . In the event of any equity restructuring (within the meaning of Financial Accounting Standards No. 123R), such as a stock dividend, stock split, spinoff, rights offering or recapitalization through a large, nonrecurring cash dividend, the Committee shall cause an equitable adjustment to be made (i) in the number and kind of Shares that may be delivered under the Plan, (ii) in the individual limitations set forth in Section 4.3 and (iii) with respect to outstanding Awards, in the number and kind of Shares subject to outstanding Awards, the Option Exercise Price, Base Value or other price of Shares subject to outstanding Awards, any performance conditions relating to Shares, the market price of Shares, or per-Share results, and other terms and conditions of outstanding Awards, in the case of (i), (ii) and (iii) to prevent dilution or enlargement of rights. In the event of any other change in corporate capitalization, such as a merger, consolidation or liquidation, the Committee may, in its sole discretion, cause an equitable adjustment as described in the foregoing sentence to be made, to prevent dilution or enlargement of rights. The number of Shares subject to any Award shall always be rounded down to a whole number when adjustments are made pursuant to this Section 4.2. Adjustments made by the Committee pursuant to this Section 4.2 shall be final, binding and conclusive.

4.3 Individual Limitations . Subject to Section 4.2 above, (i) the total number of Shares with respect to which Options or SARs may be granted in any calendar year to any Covered Employee shall not exceed 250,000 Shares; (ii) the total number of Qualified Restricted Stock Shares or Qualified Restricted Stock Units that may be granted in any calendar year to any Covered Employee shall not exceed 250,000 Shares or Units, as the case may be; (iii) the total number of Performance Shares or Performance Units that may be granted in any calendar year to any Covered Employee shall not exceed 250,000 Shares or Units, as the case may be; (iv) the total number of Shares that are intended to qualify as performance-based compensation under Section 162(m) of the Code granted pursuant to Article 10 herein in any calendar year to any Covered Employee shall not exceed 250,000 Shares; (v) the total cash Award that is intended to qualify as performance-based compensation under Section 162(m) of the Code that may be paid pursuant to Article 10 herein in any calendar year to any Covered Employee shall not exceed $500,000; and (vi) the aggregate amount of Dividend Equivalents that are intended to qualify as performance-based compensation under Section 162(m) of the Code that a Covered Employee may receive in any calendar year shall not exceed $1,000,000.

4.4 Direct Registration. Except as provided in Section 8.4 herein, Shares issued pursuant to the Plan will be recorded in the Participant’s direct registration account and a direct registration statement will be issued to the Participant, unless the Participant specifically requests a stock certificate.

Article 5. Eligibility and Participation

5.1 Eligibility . Persons eligible to participate in the Plan ("Eligible Persons") include all officers, key employees and directors of the Company and its Subsidiaries, as determined by the Committee.

5.2 Actual Participation . Subject to the provisions of the Plan, the Committee may, from time to time, select from all Eligible Persons those to whom Awards shall be granted.

Article 6. Stock Options

6.1 Grant of Options . Subject to the terms and conditions of the Plan, Options may be granted to an Eligible Person at any time and from time to time, as shall be determined by the Committee.

The Committee shall have complete discretion in determining the number of Shares subject to Options granted to each Eligible Person (subject to Article 4 herein) and, consistent with the provisions of the Plan, in determining the terms and conditions pertaining to such Options. The Committee may grant ISOs, NQSOs or a combination thereof.

6.2 Option Award Agreement . Each Option grant shall be evidenced by an Option Award Agreement that shall specify the Option Exercise Price, the term of the Option, the number of Shares to which the Option pertains, the Exercise Period and such other provisions as the Committee shall determine. The Option Award Agreement shall also specify whether the Option is intended to be an ISO or a NQSO. Rights, if any, to Dividend Equivalents shall be determined by the Committee.

6.3 Option Exercise Price . Except for Options adjusted or granted pursuant to Article 4 herein, and replacement Options granted in connection with a merger, acquisition, reorganization or similar transaction, the Option Exercise Price of Options granted under the Plan shall be at least equal to the Fair Market Value of a Share on the date of grant of the Option. Except as provided in Articles 4 and 13 herein, the following actions may not be taken with respect to outstanding Options without prior shareholder approval: (i) reduction of the Option Exercise Price of outstanding Options, (ii) cancellation of outstanding Options in exchange for cash, other Awards or Options with a lower Option Exercise Price at a time when the Option Exercise Price exceeds the Fair Market Value of a Share and (iii) any other action with respect to outstanding Options that would constitute a "re-pricing" (determined in accordance with generally accepted accounting principles, as amended from time to time and applied in preparing the Company’s financial statements, or other successor accounting principles similarly applied).

6.4 Exercise of and Payment for Options . Options granted under the Plan shall be exercisable at such times and shall be subject to such restrictions and conditions as the Committee shall in each instance approve.

Options shall be exercised by the delivery of a written notice of exercise to the Company, setting forth the number of Shares with respect to which the Option is to be exercised, accompanied by provision for full payment for the Shares.

The Option Exercise Price shall be payable: (a) in cash or its equivalent, (b) by tendering (or attesting to the ownership of) previously acquired Shares having an aggregate Fair Market Value at the time of exercise equal to the total Option Exercise Price, (c) by broker-assisted cashless exercise, (d) by such other methods as the Committee may prescribe or (e) by a combination of (a), (b), (c) and/or (d).

6.5 Termination . Each Option Award Agreement shall set forth the extent to which the Participant shall have the right to exercise the Option following termination of the Participant's employment with or service on the Board of the Company and its Subsidiaries. Such provisions shall be determined in the sole discretion of the Committee (subject to applicable law), need not be uniform among all Options granted pursuant to the Plan or among Participants and may reflect distinctions based on the reasons for termination.

6.6 Transferability of Options . Except as otherwise determined by the Committee, all Options granted to a Participant under the Plan shall be exercisable during his or her lifetime only by such Participant, and no Option granted under the Plan may be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution. ISOs are not transferable other than by will or by the laws of descent and distribution.

Article 7. Stock Appreciation Rights

7.1 Grant of SARs . Subject to the terms and conditions of the Plan, an SAR may be granted to an Eligible Person at any time and from time to time as shall be determined by the Committee. The Committee may grant Freestanding SARs, Tandem SARs or any combination of these forms of SARs.

The Committee shall have complete discretion in determining the number of SARs granted to each Eligible Person (subject to Article 4 herein) and, consistent with the provisions of the Plan, in determining the terms and conditions pertaining to such SARs. Rights, if any, to Dividend Equivalents shall be determined by the Committee.

Except for SARs adjusted or granted pursuant to Article 4 herein, and replacement SARs granted in connection with a merger, acquisition, reorganization or similar transaction, the Base Value of a Freestanding SAR shall equal the Fair Market Value of a Share on the date of grant of the SAR. The Base Value of Tandem SARs shall equal the Option Exercise Price of the related Option.

Except as provided in Articles 4 and 13 herein, the following actions may not be taken with respect to outstanding SARs without prior shareholder approval: (i) reduction of the Base Value of outstanding SARs, (ii) cancellation of outstanding SARs in exchange for cash, other Awards or SARs with a lower Base Value at a time when the Base Value exceeds the Fair Market Value of a Share and (iii) any other action with respect to outstanding SARs that would constitute a "re-pricing" (determined in accordance with generally accepted accounting principles, as amended from time to time and applied in preparing the Company’s financial statements, or other successor accounting principles similarly applied).

7.2 SAR Award Agreement . Each SAR grant shall be evidenced by an SAR Award Agreement that shall specify the number of SARs granted, the Base Value, the term of the SAR, the Exercise Period and such other provisions as the Committee shall determine.

7.3 Exercise and Payment of SARs . Tandem SARs may be exercised for all or part of the Shares subject to the related Option upon the surrender of the right to exercise the equivalent portion of the related Option. A Tandem SAR may be exercised only with respect to the Shares for which its related Option is then exercisable.

Notwithstanding any other provision of the Plan to the contrary, with respect to a Tandem SAR granted in connection with an ISO: (i) the Tandem SAR will expire no later than the expiration of the underlying ISO; (ii) the value of the payout with respect to the Tandem SAR may be for no more than one hundred percent (100%) of the difference between the Option Exercise Price of the underlying ISO and the Fair Market Value of the Shares subject to the underlying ISO at the time the Tandem SAR is exercised; and (iii) the Tandem SAR may be exercised only when the Fair Market Value of the Shares subject to the ISO exceeds the Option Exercise Price of the ISO.

Freestanding SARs may be exercised upon whatever terms and conditions the Committee, in its sole discretion, imposes upon them.

A Participant may exercise an SAR at any time during the Exercise Period. SARs shall be exercised by the delivery of a written notice of exercise to the Company, setting forth the number of SARs being exercised. Upon exercise of an SAR, a Participant shall be entitled to receive payment from the Company in an amount equal to the product of:

(a) the excess of (i) the Fair Market Value of a Share on the date of exercise over (ii) the Base Value multiplied by

(b) the number of Shares with respect to which the SAR is exercised.

At the sole discretion of the Committee, the payment to the Participant upon SAR exercise may be in cash, in Shares of equivalent value or in some combination thereof.

7.4 Termination . Each SAR Award Agreement shall set forth the extent to which the Participant shall have the right to exercise the SAR following termination of the Participant's employment with or service on the Board of the Company and its Subsidiaries. Such provisions shall be determined in the sole discretion of the Committee, need not be uniform among all SARs granted pursuant to the Plan or among Participants and may reflect distinctions based on the reasons for termination.

7.5 Transferability of SARs . Except as otherwise determined by the Committee, all SARs granted to a Participant under the Plan shall be exercisable during his or her lifetime only by such Participant or his or her legal representative, and no SAR granted under the Plan may be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution.

Article 8. Restricted Stock and Restricted Stock Units

8.1 Grant of Restricted Stock and Restricted Stock Units . Subject to the terms and conditions of the Plan, Restricted Stock and/or Restricted Stock Units may be granted to an Eligible Person at any time and from time to time, as shall be determined by the Committee.

The Committee shall have complete discretion in determining the number of shares of Restricted Stock and/or Restricted Stock Units granted to each Eligible Person (subject to Article 4 herein) and, consistent with the provisions of the Plan, in determining the terms and conditions pertaining to such Awards.

In addition, the Committee may, prior to or at the time of grant, designate an Award of Restricted Stock or Restricted Stock Units as Qualified Restricted Stock or Qualified Restricted Stock

Units, as the case may be, in which event it will condition the grant or vesting, as applicable, of such Qualified Restricted Stock or Qualified Restricted Stock Units, as the case may be, upon the attainment of the Performance Goals selected by the Committee.

8.2 Restricted Stock/Restricted Stock Unit Award Agreement . Each grant of Restricted Stock and/or Restricted Stock Units shall be evidenced by a Restricted Stock and/or Restricted Stock Unit Award Agreement that shall specify the number of shares of Restricted Stock and/or Restricted Stock Units granted, the initial value (if applicable), the Period or Periods of Restriction, and such other provisions as the Committee shall determine.

8.3 Transferability . Restricted Stock and Restricted Stock Units granted hereunder may not be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated until the end of the applicable Period of Restriction established by the Committee. During the applicable Period of Restriction, all rights with respect to the Restricted Stock and Restricted Stock Units granted to a Participant under the Plan shall be available during his or her lifetime only to such Participant or his or her legal representative.

8.4 Certificates and Account Entries . Restricted Stock shall be registered in the name of a Participant and held in the Company's custody until such time as all restrictions applicable to such Shares have been satisfied.

8.5 Removal of Restrictions . Restricted Stock shall become freely transferable by the Participant after the last day of the Period of Restriction applicable thereto. Once Restricted Stock is released from the restrictions, the number of Shares with respect to which the restrictions have lapsed will be recorded in the Participant’s direct registration account and a direct registration statement will be issued to the Participant, unless the Participant specifically requests a stock certificate. Payment of Restricted Stock Units shall be made after the last day of the Period of Restriction applicable thereto. The Committee, in its sole discretion, may pay Restricted Stock Units in cash or in Shares (or in a combination thereof), which have an aggregate Fair Market Value equal to the value of the Restricted Stock Units.

8.6 Voting Rights . During the Period of Restriction, Participants may exercise full voting rights with respect to the Restricted Stock.

8.7 Dividends and Other Distributions . Subject to the Committee's right to determine otherwise, during the Period of Restriction, Participants shall receive all regular cash dividends paid with respect to the Restricted Stock while it is so held, and all other distributions paid with respect to such Restricted Stock shall be credited to Participants subject to the same restrictions on transferability and forfeitability as the Restricted Stock with respect to which they were paid and shall vest or be paid, as the case may be, to the Participant promptly after the full vesting of the Restricted Stock with respect to which such distributions were made.

Rights, if any, to Dividend Equivalents on Restricted Stock Units shall be determined by the Committee.

8.8 Termination . Each Restricted Stock/Restricted Stock Unit Award Agreement shall set forth the extent to which the Participant shall have the right to receive Restricted Stock and/or a Restricted Stock Unit payment following termination of the Participant's employment with or service on the Board of the Company and its Subsidiaries. Such provisions shall be determined in the sole discretion of the Committee, need not be uniform among all grants of Restricted Stock/Restricted Stock Units or among Participants and may reflect distinctions based on the reasons for termination.

Article 9. Performance Units and Performance Shares

9.1 Grant of Performance Units and Performance Shares . Subject to the terms and conditions of the Plan, Performance Units and/or Performance Shares may be granted to an Eligible Person at any time and from time to time, as shall be determined by the Committee.

The Committee shall have complete discretion in determining the number of Performance Units and/or Performance Shares granted to each Eligible Person (subject to Article 4 herein) and, consistent with the provisions of the Plan, in determining the terms and conditions pertaining to such Awards.

9.2 Performance Unit/Performance Share Award Agreement . Each grant of Performance Units and/or Performance Shares shall be evidenced by a Performance Unit and/or Performance Share Award Agreement that shall specify the number of Performance Units and/or Performance Shares granted, the initial value (if applicable), the Performance Period, the Performance Goals and such other provisions as the Committee shall determine. Rights, if any, to Dividend Equivalents shall be determined by the Committee.

9.3 Value of Performance Units/Performance Shares . Each Performance Unit shall have an initial value that is established by the Committee at the time of grant. In no event shall the value of a Performance Unit intended to qualify as performance-based compensation under Code Section 162(m) exceed the value of a Share. The value of a Performance Share shall be equal to the Fair Market Value of a Share. The Committee shall set Performance Goals in its discretion which, depending on the extent to which they are met, will determine the number and/or value of Performance Units/Performance Shares that will be paid out to the Participants.

9.4 Earning of Performance Units/Performance Shares . After the applicable Performance Period has ended, the Participant shall be entitled to receive a payout with respect to the Performance Units/Performance Shares earned by the Participant over the Performance Period, to be determined as a function of the extent to which the corresponding Performance Goals have been achieved.

9.5 Form and Timing of Payment of Performance Units/Performance Shares . Payment of earned Performance Units/Performance Shares shall be made following the close of the applicable Performance Period. The Committee, in its sole discretion, may pay earned Performance Units/Shares in cash or in Shares (or in a combination thereof), which have an aggregate Fair Market Value equal to the value of the earned Performance Units/Shares at the close of the applicable Performance Period. Such Shares may be granted subject to any restrictions deemed appropriate by the Committee.

9.6 Termination . Each Performance Unit/Performance Share Award Agreement shall set forth the extent to which the Participant shall have the right to receive a Performance Unit/Performance Share payment following termination of the Participant's employment with or service on the Board of the Company and its Subsidiaries during a Performance Period. Such provisions shall be determined in the sole discretion of the Committee, need not be uniform among all grants of Performance Units/Performance Shares or among Participants and may reflect distinctions based on reasons for termination.

9.7 Transferability . Except as otherwise determined by the Committee, a Participant's rights with respect to Performance Units/Performance Shares granted under the Plan shall be available during the Participant's lifetime only to such Participant or the Participant's legal representative and Performance Units/Performance Shares may not be sold, transferred, pledged, assigned or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution.

Article 10. Other Awards

The Committee shall have the right to grant other Awards which may include, without limitation, the grant of Shares based on attainment of Performance Goals established by the Committee, the payment of Shares in lieu of cash or cash based on attainment of Performance Goals established by the Committee, and the payment of Shares in lieu of cash under other Company incentive or bonus programs. Payment under or settlement of any such Awards shall be made in such manner and at such times as the Committee may determine.

Article 11. Deferrals

The Committee may permit a Participant to defer the Participant's receipt of the payment of cash or the delivery of Shares that would otherwise be due to such Participant under the Plan. If any such deferral election is permitted, the Committee shall, in its sole discretion, establish rules and procedures for such payment deferrals.

Article 12. Rights of Participants

12.1 Termination . Nothing in the Plan shall interfere with or limit in any way the right of the Company or any Subsidiary to terminate any Participant's employment or other relationship with the Company or any Subsidiary at any time, for any reason or no reason in the Company's or the Subsidiary's sole discretion, nor confer upon any Participant any right to continue in the employ of, or otherwise in any relationship with, the Company or any Subsidiary.

12.2 Participation . No Eligible Person shall have the right to be selected to receive an Award under the Plan, or, having been so selected, to be selected to receive a future Award.

12.3 Limitation of Implied Rights . Neither a Participant nor any other Person shall, by reason of the Plan, acquire any right in or title to any assets, funds or property of the Company or any Subsidiary whatsoever, including, without limitation, any specific funds, assets or other property which the Company or any Subsidiary, in their sole discretion, may set aside in anticipation of a liability under the Plan. A Participant shall have only a contractual right to the Shares or amounts, if any, payable under the Plan, unsecured by any assets of the Company or any Subsidiary. Nothing contained in the Plan shall constitute a guarantee that the assets of such companies shall be sufficient to pay any benefits to any Person.

Except as otherwise provided in the Plan, no Award under the Plan shall confer upon the holder thereof any right as a shareholder of the Company prior to the date on which the individual fulfills all conditions for receipt of such rights.

Article 13. Change in Control

The terms of this Article 13 shall immediately become operative, without further action or consent by any Person, upon a Change in Control, and once operative shall supersede and take control over any other provisions of this Plan.

Upon a Change in Control

(a) Any and all Options and SARs granted hereunder shall become immediately vested and exercisable;

(b) Any restriction periods and restrictions imposed on Restricted Stock, Restricted Stock Units, Qualified Restricted Stock or Qualified Restricted Stock Units shall be deemed to have expired; any Performance Goals shall be deemed to have been met at the target level; such Restricted Stock and Qualified Restricted Stock shall become immediately vested in full, and such Restricted Stock Units and Qualified Restricted Stock Units shall be paid out in cash on the date of the Change in Control or as soon as practicable (but not more than 60 days) following the date of the Change in Control;

(c) The target payout opportunity attainable under all outstanding Awards of Performance Units and Performance Shares and any Awards granted pursuant to Article 10 shall be deemed to have been fully earned for the entire Performance Period(s) as of the effective date of the Change in Control. All such Awards shall become immediately vested. All Performance Shares and other Awards granted pursuant to Article 10 denominated in Shares shall be paid out in Shares, and all Performance Units and other Awards granted pursuant to Article 10 shall be paid out in cash, in each case, on the date of the Change in Control or as soon as practicable (but not more than 60 days) following the date of the Change in Control; and

(d) All credited but not yet paid cash dividends and Dividend Equivalents attributable to the portion of any Award that vests, is earned and/or is paid, as the case may be, pursuant to this Article 13 shall be paid in cash on the date of the Change in Control or as soon as practicable (but not more than 60 days) following the date of the Change in Control.

Notwithstanding anything contained herein or in any Award Agreement to the contrary, no payment or distribution under the Plan or pursuant to an Award that (1) is determined by the Company to be deferred compensation subject to Code Section 409A and (2) would be distributed because of a Change in Control shall be so distributed because of the Change in Control pursuant to this Article 13 unless the distribution qualifies under Code Section 409A(a)(2)(A)(v) as a distribution upon a change in ownership or effective control or a change in the ownership of a substantial portion of assets or otherwise qualifies as a permissible distribution under Code Section 409A. To the extent an amount would have been distributed pursuant to an Award because of a Change in Control pursuant to this Article 13, but the distribution is prohibited by the prior sentence, the following shall occur: (i) the Award shall nevertheless vest or be deemed earned, as the case may be, pursuant to Sections (a), (b), (c) and/or (d) of this Article 13 as of the date of the Change in Control (except to the extent it would violate Code Section 409A), but distribution of such vested or earned amounts shall not occur until the event or date distribution would have occurred absent the Change in Control and (ii) no further dividends or Dividend Equivalents shall be credited with respect to the Award after the date of the Change in Control.

In the event of a Change in Control, the Board or the board of directors of any surviving entity or acquiring entity may provide or require that the surviving or acquiring entity shall: (1) assume or continue all or any part of the Options and SARs outstanding under the Plan or (2) substitute substantially equivalent Options and SARs (including an award to acquire substantially the same consideration paid to the shareholders in the transaction by which the Change in Control occurs) for those outstanding under the Plan. In the event any surviving entity or acquiring entity refuses to assume or continue such Awards or to substitute similar awards for those outstanding under the Plan, then with respect to Awards held by Participants whose continuous service has not terminated, the Board in its sole discretion and without liability to any person may: (1) provide for the payment of a cash amount in exchange for the cancellation of an Option or SAR equal to the product of (x) the excess, if any, of the Fair Market Value per Share at such time over the Option Exercise Price or Base Value, as the case may be, if any, times (y) the total number of Shares then subject to such Award; (2) continue the Awards; or (3) notify Participants holding

an Option or SAR that they must exercise or redeem any portion of such Award (including, at the discretion of the Board, any unvested portion of such Award) at or prior to the closing of the transaction by which the Change in Control occurs and that the Awards shall terminate if not so exercised or redeemed at or prior to the closing of the transaction by which the Change in Control occurs. The Board shall not be obligated to treat all Awards, even those that are of the same type, in the same manner.

Article 14. Amendment, Modification and Termination

14.1 Amendment, Modification and Termination . The Board may, at any time and from time to time, alter, amend, suspend or terminate the Plan in whole or in part.

14.2 Awards Previously Granted . No termination, amendment or modification of the Plan shall adversely affect in any material way any Award previously granted under the Plan without the written consent of the Participant holding such Award, unless such termination, modification or amendment is required by applicable law and except as otherwise provided herein.

Article 15. Withholding

15.1 Tax Withholding. The Company shall have the power and the right to deduct or withhold, or require a Participant to remit to the Company, an amount (including any Shares withheld as provided below) sufficient to satisfy Federal, state and local taxes (including the Participant's FICA obligation) required by law to be withheld with respect to an Award made under the Plan.

15.2 Share Withholding . With respect to tax withholding required upon the exercise of Options or SARs, upon the lapse of restrictions on Restricted Stock, or upon any other taxable event arising out of or as a result of Awards granted hereunder, subject to such restrictions as the Committee may prescribe, Participants may elect to satisfy the withholding requirement, in whole or in part, by tendering Shares held by the Participant or by having the Company withhold Shares with a value that does not exceed the employer’s minimum statutory tax rate; provided, however, that, in the discretion of the Committee and to the extent permitted under applicable financial accounting standards, the value of Shares so tendered or withheld may exceed the employer’s minimum statutory tax rate but may not be greater than the maximum statutory tax rate. All elections shall be irrevocable, made in writing and signed by the Participant.

Article 16. Successors

All obligations of the Company under the Plan, with respect to Awards granted hereunder, shall be binding on any successor to the Company, whether the existence of such successor is the result of a direct or indirect purchase, merger, consolidation or otherwise of all or substantially all of the business and/or assets of the Company.

Article 17. Legal Construction

17.1 Gender and Number . Except where otherwise indicated by the context, any masculine term used herein also shall include the feminine, the plural shall include the singular and the singular shall include the plural.

17.2 Severability . In the event any provision of the Plan shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Plan, and the Plan shall be construed and enforced as if the illegal or invalid provision had not been included.

17.3 Requirements of Law . The granting of Awards and the issuance of Shares under the Plan shall be subject to all applicable laws, rules and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required.

17.4 Governing Law . To the extent not preempted by Federal law, the Plan, and all agreements hereunder, shall be construed in accordance with, and governed by, the laws of the State of Idaho without regard to any conflicts of law or choice of law rule or principle that might otherwise reference construction or interpretation of the Plan or any agreements hereunder to the substantive law of another jurisdiction.

17.5 Section 409A . No amendment to the Plan made pursuant to the amendments approved by the Board on March 17, 2005, July 20, 2006 or November 20, 2008 shall be applicable to an Award that is not subject to Section 409A of the Code to the extent such amendment would cause the Award to become subject to Section 409A of the Code. To the extent applicable to an Award that provides for the payment of deferred compensation subject to Section 409A of the Code, it is intended that the Plan will comply with Section 409A of the Code and any regulations and guidance issued thereunder, and the Plan shall be interpreted accordingly. To the extent an Award is subject to Section 409A of the Code and payment of deferred compensation pursuant to the Award is to be made because of the Participant's termination of employment or termination of service as a Director, notwithstanding anything to the contrary contained in the Plan, the Participant's Award Agreement or any other plan or agreement that governs payment of the Award, the Participant's employment or service as a Director shall not be deemed to have terminated unless and until the Participant has experienced a Separation from Service. Notwithstanding anything contained herein or in any Award Agreement to the contrary, if it is determined that any amounts to be provided upon a Separation from Service constitute deferred compensation for purposes of Section 409A of the Code and the Participant is a "specified employee," as determined under the Company’s policy for determining specified employees, on the date on which the Separation from Service occurs, no such amounts shall be provided before the date that is six months following the Participant’s Separation from Service unless the Participant dies during such six-month period, in which case payment may be made as soon as practicable (but not more than 60 days) after the Participant’s death. If the Participant's Award Agreement (or any other plan or agreement that governs payment of the Award) provides for payment to occur as soon as practicable after an event, date or time period, and payment of the Award is to be made pursuant to that provision, in no event will the payment be made more than 60 days after such event, date or time period.

Adopted by the Board January 20, 2000 Approved by the Shareholders May 11, 2000

Amended by the Board January 18, 2001

Approved by the Shareholders May 17, 2001

Amended by the Board March 17, 2005

Approved by the Shareholders May 19, 2005

Amended by the Board July 20, 2006

Amended by the Board September 20, 2007

Amended by the Board November 20, 2008

Amended by the Board November 18, 2010

Amended by the Board February 9, 2017

*****

ADDITIONAL INFORMATION

Resale Restrictions

While the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan (the “Plan”) does not place restrictions on resales of common stock, shares of common stock acquired pursuant to the Plan by an "affiliate," as that term is defined in Rule 405 of the Securities Act of 1933, as amended (the “Securities Act”), of IDACORP, Inc. (the “Company”) may be resold only pursuant to the registration requirements of the Securities Act or an applicable exemption therefrom. In addition, acquisitions and dispositions of the Company’s common stock or derivative securities by persons subject to Section 16 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), within any period of less than six months may give rise to the right of the Company to recapture any profit from such transactions pursuant to Section 16(b) of the Exchange Act.

ERISA

The Plan is not subject to any provisions of the Employee Retirement Income Security Act of 1974.

Federal Income Tax Consequences

NOTE: The following discussion of income tax consequences is not a complete description of the federal income tax aspects of the Plan. In addition, administrative and judicial interpretations of the application of the federal income tax laws are subject to change. Furthermore, the following discussion does not address state or local tax consequences. RECIPIENTS OF AWARDS UNDER THE PLAN ARE ADVISED TO CONSULT THEIR PERSONAL TAX ADVISORS WITH REGARD TO ALL TAX CONSEQUENCES ARISING WI1H RESPECT TO THEIR AWARDS.

The Plan is not qualified under Section 401(a) of the Internal Revenue Code.

The following is a brief description of the federal income tax consequences of the Plan.

Stock Options

Consequences to the Optionholder

Grant . There are no federal income tax consequences to the optionholder solely by reason of the grant of incentive stock options (“ISOs”) or non-qualified stock options (“NQSOs”) under the Plan.

Exercise . The exercise of an ISO is not a taxable event for regular federal income tax purposes if certain requirements are satisfied, including the requirement that the optionholder generally must exercise the ISO no later than three months following the termination of the optionholder's employment with the Company. However, such exercise may give rise to alternative minimum tax liability (see "Alternative Minimum Tax" below).

Upon the exercise of a NQSO, the optionholder will generally recognize ordinary income in an amount equal to the excess of the fair market value of the shares of common stock at the time of exercise over the amount paid therefor by the optionholder as the exercise price. The ordinary income recognized in connection with the exercise by an optionholder of a NQSO will be subject to both wage and employment tax withholding.

The optionholder's tax basis in the shares acquired pursuant to the exercise of an option will be the amount paid upon exercise plus, in the case of a NQSO, the amount of ordinary income, if any, recognized by the optionholder upon exercise thereof.

Qualifying Disposition . If an optionholder disposes of shares of Company common stock acquired upon exercise of an ISO in a taxable transaction, and such disposition occurs more than two years from the date on which the option was granted and more than one year after the date on which the shares were transferred to the optionholder pursuant to the exercise of the ISO, the optionholder will recognize long-term capital gain or loss equal to the difference between the amount realized upon such disposition and the optionholder's adjusted basis in the shares (generally the option exercise price).

Disqualifying Disposition . If the optionholder disposes of shares of Company common stock acquired upon the exercise of an ISO (other than in certain tax-free transactions) within two years from the date on which the ISO was granted or within one year after the transfer of shares to the optionholder pursuant to the exercise of the ISO, at the time of disposition the optionholder will generally recognize ordinary income equal to the lesser of (i) the excess of each such share's fair market value on the date of exercise over the exercise price paid by the optionholder, or (ii) the optionholder's actual gain (i.e., the excess, if any, of the amount realized on the disposition over the exercise price paid by the optionholder). If the total amount realized on a taxable disposition (including return of capital and capital gain) exceeds the fair market value on the date of exercise of the shares of Company common stock purchased by the optionholder under the option, the optionholder will recognize a capital gain in the amount of such excess. If the optionholder incurs a loss on the disposition (i.e., if the total amount realized is less than the exercise price paid by the optionholder), the loss will be a capital loss.

Other Disposition . If an optionholder disposes of shares of Company common stock acquired upon exercise of a NQSO in a taxable transaction, the optionholder will recognize capital gain or loss in an amount equal to the difference between the optionholder's basis (as discussed above) in the shares sold and the total amount realized upon disposition. Any such capital gain or loss (and any capital gain or loss recognized on a disqualifying disposition of shares of Company common stock acquired upon exercise of ISOs as discussed above) will be short-term or long-term depending on whether the shares of Company common stock were held for more than one year from the date such shares were transferred to the optionholder.

Alternative Minimum Tax . Alternative minimum tax ("AMT") is payable if and to the extent the amount thereof exceeds the amount of the taxpayer's regular tax liability, and any AMT paid generally may be credited against future regular tax liability (but not future AMT liability). AMT applies to alternative minimum taxable income; generally, regular taxable income as adjusted for tax preferences and other items is treated differently under the AMT.

For AMT purposes, the spread upon exercise of an ISO (but not a NQSO) will be included in alternative minimum taxable income, and the taxpayer will receive a tax basis equal to the fair market value of the shares of Company common stock at such time for subsequent AMT purposes. However, if the optionholder disposes of the ISO shares in the year of exercise, the AMT income cannot exceed the gain recognized for regular tax purposes, provided that the disposition meets certain third-party requirements for limiting the gain on a disqualifying disposition. If there is a disqualifying disposition in a year other than the year of exercise, the income on the disqualifying disposition is not considered alternative minimum taxable income.

Consequences to the Company

There are no federal income tax consequences to the Company by reason of the grant of ISOs or NQSOs or the exercise of an ISO (other than disqualifying dispositions).

At the time the optionholder recognizes ordinary income from the exercise of a NQSO, the Company will be entitled to a federal income tax deduction in the amount of the ordinary income so recognized (as described above). To the extent the optionholder recognizes ordinary income by reason of a disqualifying disposition of the stock acquired upon exercise of an ISO, the Company will be entitled to a corresponding deduction in the year in which the disposition occurs.

The Company will be required to report to the Internal Revenue Service any ordinary income recognized by any optionholder by reason of the exercise of a NQSO. The Company will be required to withhold income and employment taxes (and pay the employer's share of employment taxes) with respect to ordinary income recognized by the optionholder upon the exercise of NQSOs.

Stock Appreciation Rights

The recipient of a stock appreciation right (“SAR”) is not taxed and the Company is not entitled to a federal income tax deduction at the time of grant. When the SAR is exercised, the recipient recognizes ordinary income in an amount equal to the amount of cash received and the fair market value of shares of stock received, and the Company will be entitled to a federal income tax deduction in an amount equal to such amount.

Restricted Stock Awards

The grantee of Restricted Stock Awards is not taxed and the Company is not entitled to a federal income tax deduction at the time of grant. However, when shares of Restricted Stock are no longer subject to a substantial risk of forfeiture, the grantee recognizes ordinary income in an amount equal to the fair market value of the stock less the amount paid, if any, for the stock. Alternatively, the grantee of shares of Restricted Stock may file an election with the Internal Revenue Service within 30 days of the date of his or her receipt of the shares to recognize ordinary income at the time of grant rather than at the time the restrictions lapse. The Company is entitled to a federal income tax deduction in an amount equal to the fair market value of the stock at the time the grantee recognizes income related to the grant of Restricted Stock.

Restricted Stock Units

The grantee of Restricted Stock Units is not taxed and the Company is not entitled to a federal income tax deduction at the time of grant. The grantee will recognize ordinary income at the time, and to the extent, the award becomes nonforfeitable following the end of the restriction period in an amount equal to the amount of cash or fair market value of Company common stock received. The Company is entitled to a deduction in the same amount and at the same time as the grantee recognizes ordinary income.

Performance Units and Performance Shares

The grantee of performance units and performance shares is not taxed and the Company is not entitled to a federal income tax deduction at the time of grant. The grantee will recognize ordinary income at the time of payment following the end of the performance period (subject to the special rules applicable if the performance units are paid in restricted stock) in an amount equal to the amount of cash or fair market

value of Company common stock received. The Company is entitled to a deduction in the same amount and at the same time as the grantee recognizes ordinary income.

Liens

No person, under the Plan or any contract therein, has, or may create, a lien on any funds, securities, or other property held under the Plan.

Information Concerning IDACORP, Inc. and Statement of Availability

The Company hereby undertakes to provide without charge to each participant to whom this document is delivered, upon written or oral request of such participant, a copy of any and all the documents that have been incorporated by reference in Item 3 of Part II of the latest registration statement on Form S-8 relating to the Plan (which documents are incorporated by reference into the Section 10(a) prospectus) and any other documents required to be delivered to participants pursuant to Rule 428(b) of the Securities Act.

Requests for all documents and additional information about the Plan and its administrators should be addressed to:

IDACORP, Inc.

Attention: Human Resource Department

1221 West Idaho Street

Boise, Idaho

(208) 388-2200

The Company’s Annual Report on Form 10-K for the most recently completed fiscal year is available on the Company’s web site, www.idacorpinc.com .

Exhibit 10.42

IDACORP, Inc.

2000 LONG-TERM INCENTIVE AND COMPENSATION PLAN

RESTRICTED STOCK UNIT AGREEMENT

(Time vesting)

___________ , 20__

[[FIRSTNAME]] [[LASTNAME]]

In accordance with the terms of the 2000 Long-Term Incentive and Compensation Plan (the "Plan"), pursuant to action of the Compensation Committee (the "Committee") of the Board of Directors, IDACORP, Inc. (the "Company") hereby grants to you (the "Participant"), subject to the terms and conditions set forth in this Restricted Stock Unit Agreement (including Annex A hereto and all documents incorporated herein by reference), an award of restricted stock units, or a right to receive shares of Company common stock (the "RSUs"), as set forth below:



Date of Grant:	___________ , 20__
Number of RSUs:	[[SHARESGRANTED]]
Restricted Period:	__/__/20__ through __/__/20__
Vesting Schedule:	All of the RSUs subject to this Award shall vest on __/__/20__ if the Participant remains employed through the Restricted Period.

THESE RSUs ARE SUBJECT TO FORFEITURE AS PROVIDED IN ANNEX A AND THE PLAN.

Further terms and conditions of the Award are set forth in Annex A hereto, which is an integral part of this Restricted Stock Unit Agreement.

All terms, provisions and conditions applicable to the Award set forth in the Plan and not set forth herein are hereby incorporated by reference herein. To the extent any provision hereof is inconsistent with the Plan, the Plan will govern. The Participant hereby acknowledges receipt of a copy of this Restricted Stock Unit Agreement including Annex A hereto and a copy of the Plan and agrees to be bound by all the terms and provisions hereof and thereof.

IDACORP, Inc.

By: [[SIGNATURE]]

________________________________

[[FIRSTNAME]] [[LASTNAME]]

Agreed :

[[SIGNATURE]]

________________________________

[[FIRSTNAME]] [[LASTNAME]]

Address:

[[RESADDR1]] [[RESADDR2]]

[[RESCITY]], [[RESSTATEORPROV]] [[RESPOSTALCODE]]

Attachment: Annex A

ANNEX A

IDACORP, INC. 2000 LONG-TERM INCENTIVE AND COMPENSATION PLAN

RESTRICTED STOCK UNIT AGREEMENT

It is understood and agreed that the Award of Restricted Stock Units (“RSUs”) evidenced by the Restricted Stock Unit Agreement to which this is annexed is subject to the following additional terms and conditions:

1. Forfeiture and Transfer Restrictions .


A.	Forfeiture Restrictions . Except as provided otherwise in Section 2 of this Annex A, if the Participant's employment is terminated during the Restricted Period, the RSUs subject to this Award shall be forfeited as of the date of termination.


B.	Transfer Restrictions . The RSUs may not be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated.

2. Termination of Employment . If the Participant's employment is terminated during the Restricted Period (i) due to the Participant's death or disability or (ii) with the approval of the Committee due to the Participant's retirement, the RSUs shall vest on the date of such termination of employment (unless the date of termination of employment is the final day of the Restricted Period, in which case the RSUs shall vest on the Vesting Schedule date set forth on page 1 of the Restricted Stock Unit Agreement) with respect to a prorated number of RSUs determined by multiplying the total number of RSUs subject to this Award times a fraction, the numerator of which is the number of whole months having elapsed during the Restricted Period as of the date of such termination of employment and the denominator of which is the total number of whole months in the Restricted Period. For purposes of this Section 2, determination of whether a Participant's employment is terminated due to the Participant's retirement shall be made in the sole discretion of the Committee and the Committee's determination shall be final.

3. Vesting and Settlement of RSUs . Except as provided otherwise in Article 13 of the Plan and Sections 1 or 2 of this Annex A, the RSUs shall vest in accordance with the Vesting Schedule set forth in the Restricted Stock Unit Agreement. Any RSUs that do not vest shall be forfeited. The Company will settle RSUs that vest as soon as administratively practicable following the date on which the RSUs vest, but no later than March 15 of the calendar year following the calendar year in which the RSUs vest, by issuing one Share for each vested RSU.

4. No Voting Rights . The Participant shall not have voting or other rights as a shareholder of the Company with respect to the RSUs.

5. Dividend Equivalents . The Participant shall be entitled to receive regular cash dividend equivalents for each RSU in an amount equal to the cash dividends declared on a Share

during the Restricted Period; provided, however, that in no event shall the Participant receive dividends paid with respect to any forfeited RSUs on or after the date of forfeiture.

6. Tax Withholding . The Company may make such provisions as are necessary for the withholding of all applicable taxes on the RSUs, in accordance with Article 15 of the Plan.

7. Section 409A . The Company intends that the RSUs will be exempt from, or comply with, the requirements of Section 409A of the Code and the Treasury Regulations thereunder. Notwithstanding any provision in the Restricted Stock Unit Agreement to the contrary, and consistent with the Plan, the RSUs shall be interpreted, operated, and administered in a manner consistent with such intentions. The Company makes no representation that that the RSUs shall be exempt from or comply with Section 409A of the Code and makes no undertaking to preclude Section 409A of the Code from applying to the RSUs.

8. Ratification of Actions . By accepting this Award or other benefit under the Plan, the Participant and each person claiming under or through him shall be conclusively deemed to have indicated the Participant's acceptance and ratification of, and consent to, any action taken under the Plan or the Award by IDACORP, Inc.

9. Notices . Any notice hereunder to IDACORP, Inc. shall be addressed to its office at 1221 West Idaho Street, Boise, Idaho 83702; Attention: Manager of Compensation, and any notice hereunder to the Participant shall be addressed to him or her at the address specified on the Restricted Stock Unit Agreement, subject to the right of either party to designate at any time hereafter in writing some other address.

10. Definitions . Capitalized terms not otherwise defined herein shall have the meanings given them in the Plan.

11. Governing Law and Severability . To the extent not preempted by Federal law, the Restricted Stock Unit Agreement will be governed by and construed in accordance with the laws of the State of Idaho, without regard to conflicts of law provisions. In the event any provision of the Restricted Stock Unit Agreement shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Restricted Stock Unit Agreement, and the Restricted Stock Unit Agreement shall be construed and enforced as if the illegal or invalid provision had not been included.

12. Additional Information . Please see Exhibit A for additional information regarding the RSUs and related matters.

Exhibit A

Dear Participant -

A copy of the 2000 IDACORP, Inc. Long Term Incentive and Compensation Plan (“LTIP”) and supplemental information is available on the Certent Participant Portal.

Additionally, IDACORP will make available to you without charge, upon your written or oral request, a copy of any and all documents incorporated by reference in Item 3 of Part II of the latest Registration Statement on Form S-8 relating to the LTIP (which documents are incorporated by reference in the Section 10(a) prospectus) and any other documents required to be delivered to employees pursuant to Rule 428(b) of the Securities Act of 1933, as amended. This includes, but is not limited to, the most recently filed version of IDACORP’s Annual Report on Form 10-K. IDACORP’s most recent Annual Report on Form 10-K is also available on the IDACORP website, www.idacorpinc.com .

This document constitutes part of a prospectus covering securities that have been registered under the Securities Act of 1933.

Exhibit 10.43

IDACORP, Inc.

2000 LONG-TERM INCENTIVE AND COMPENSATION PLAN

PERFORMANCE UNIT AWARD AGREEMENT

Relative Total Shareholder Return

_____________, 20__

[[FIRSTNAME]] [[LASTNAME]]

In accordance with the terms of the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan (the “Plan”), pursuant to action of the Compensation Committee (the “Committee”) of the Board of Directors, IDACORP, Inc. (the “Company”) hereby grants to you (the “Participant”), subject to the terms and conditions set forth in this Performance Unit Award Agreement (including Annex A hereto and all documents incorporated herein by reference), an award of units, or a right to receive shares of Company common stock, subject to the attainment of performance target levels (“Performance Units”) and an opportunity to earn additional Performance Units if performance exceeds target levels, as set forth below:



Date of Grant:	_____________, 20__
Number of Performance Units (the “Target Award”):	[[SHARESGRANTED]]
Maximum Number of Additional Performance Units:	[[SHARESGRANTED]]
Performance Period:	__________, 20__ through ___________, 20__
Performance Goal:	IDACORP total shareholder return (“TSR”) relative to the Peer Group defined in Annex A for the Performance Period



Vesting Date:	To the extent the Performance Goal is met or exceeded, vesting of earned Performance Units subject to the Award (if any) shall occur upon completion of the Performance Period, with settlement as soon as administratively practicable in the calendar year following the Performance Period, but no later than March 15.
Dividend Equivalents:	Dividend equivalents are accrued throughout the Performance Period and paid as soon as administratively practicable, but no later than March 15 of the calendar year following the Performance Period, with respect to Performance Units subject to the Target Award that are earned and any additional Performance Units that are earned.

THESE PERFORMANCE UNITS ARE SUBJECT TO FORFEITURE AS PROVIDED IN ANNEX A AND THE PLAN.

Further terms and conditions of the Award are set forth in Annex A hereto, which is an integral part of this Performance Unit Award Agreement.

All terms, provisions and conditions applicable to the Award set forth in the Plan and not set forth herein are hereby incorporated by reference herein. To the extent any provision hereof is inconsistent with the Plan, the Plan will govern. The Participant hereby acknowledges receipt of a copy of this Performance Unit Award Agreement including Annex A hereto and a copy of the Plan and agrees to be bound by all the terms and provisions hereof and thereof.

IDACORP, Inc.

By: [[SIGNATURE]]

________________________________

[[FIRSTNAME]] [[LASTNAME]]

Agreed :

[[SIGNATURE]]

_________________________________

[[FIRSTNAME]] [[LASTNAME]]

Address:

[[RESADDR1]] [[RESADDR2]]

[[RESCITY]], [[RESSTATEORPROV]] [[RESPOSTALCODE]]

Attachment: Annex A

ANNEX A

IDACORP, Inc.

2000 LONG-TERM INCENTIVE AND COMPENSATION PLAN

PERFORMANCE UNIT AWARD AGREEMENT

Relative Total Shareholder Return

It is understood and agreed that the Award of Performance Units evidenced by the Performance Unit Award Agreement to which this is annexed is subject to the following additional terms and conditions:

1. Nature of Award . The Award represents the opportunity to receive units that settle in shares of Company common stock (“Shares”) and cash dividend equivalents on those units. The Award is subject to performance-based vesting conditions (“Performance Units”). Furthermore, if the performance results exceed target levels, additional Performance Units are earned and distributed in proportion to this excess as determined pursuant to Section 2 hereof. The amount of dividends paid on Performance Units shall be determined pursuant to Section 4 hereof.


1.	Performance Goal and Determination of Number of Performance Units Earned .

The number of Performance Units earned, if any, for the Performance Period shall be determined in accordance with the following formula:

# of Units = Payout Percentage X Target Award

If the Payout Percentage is not greater than 100%, the “# of Units” earned relates to the number of Performance Units subject to the Target Award. To illustrate, with a Target Award of 100 Performance Units, a 90% Payout Percentage would result in 90% of the Target Award being earned (90 Performance Units). If the Payout Percentage is greater than 100%, all Performance Units subject to the Target Award are earned and additional Performance Units equal to the “# of Units” in excess of the Target Award are earned. To illustrate, with a Target Award of 100 Performance Units, a 140% Payout Percentage would result in 100% of the Performance Units subject to the Target Award earned and 40 additional Performance Units earned. All Performance Units that are not earned shall be forfeited.

The “Payout Percentage” is based on the Company’s total shareholder return (“TSR”) relative to that of the Peer Group defined herein (the “Percentile Rank”) for the Performance Period, determined in accordance with the table set forth below:

TSR Table and Method of Calculation:



Percentile Rank	Payout Percentage (% of Target Award)
__ (“maximum”) or higher	___%
__ (“target”)	___%
__ (“threshold”)	___%
Less than __	___%

Performance results between threshold and target, and target and maximum, will be interpolated.

The Percentile Rank of a given company’s TSR is defined as the percentage of the Peer Group companies’ returns falling at or below the given company’s TSR. The formula for calculating the Percentile Rank follows:

Percentile Rank = (n - r + 1)/n x 100

Where:

n = total number of companies in the Peer Group, excluding the Company


r =	the numeric rank of the Company’s TSR relative to the Peer Group, where the highest return in the group is ranked number 1.

To illustrate, if the Company’s TSR is the third highest in the Peer Group comprised of 29 companies, its Percentile Rank would be __, which would result in a TSR Payout Percentage (weighted 50%) of __%. The calculation is: (29 - 3 + 1)/29 x ___ = __.

The Percentile Rank shall be rounded to the nearest whole percentage, with (.5) rounded up.

The “Peer Group” is defined as those utility companies listed in the EEI Index of U.S. Shareholder-Owned Electric Utilities at the end of the Performance Period.

Total shareholder return is the percentage change in the value of an investment in the common stock of a company from the initial investment made on the last trading day in the calendar year preceding the beginning of the Performance Period through the last trading day in the final year of the Performance Period. It is assumed that dividends are reinvested in additional shares of common stock at the frequency paid.

The total number of Performance Units earned shall be rounded to the nearest whole number of Performance Units, with (.5) rounded up.

3. Vesting and Settlement of Performance Units . Subject to Section 2, Section 6 and Section 8 hereof and Article 13 of the Plan, vesting of earned Performance Units subject to the Award (if any) shall occur upon completion of the Performance Period. The Company will settle Performance Units that have vested, as soon as administratively practicable, but no later than March 15 of the calendar year following the Performance Period, by issuing one Share for each Performance Unit vested.

4. Dividend Equivalents . The Participant shall be entitled to dividend equivalents in an amount equal to the cash dividends declared on a Share during the Performance Period with respect to Performance Units subject to the Target Award that are earned and any additional Performance Units that are earned pursuant to Section 2 hereof. Any such dividend equivalents shall be paid in cash to the Participant as soon as administratively practicable, but no later than March 15 of the calendar year following the Performance Period.

5. Forfeiture and Transfer Restrictions .


A.	Forfeiture Restrictions . Except as provided otherwise in Section 6 hereof, if the Participant’s employment is terminated during the Performance Period, Performance Units shall be forfeited as of the date of termination.


B.	Transfer Restrictions . Performance Units may not be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated during the Performance Period.

6. Termination of Employment . If the Participant’s employment is terminated during the Performance Period (i) due to the Participant’s death or Disability or (ii) due to the Participant’s Retirement, the number of Performance Units subject to the Target Award that are earned (if any) and the number of additional Performance Units earned (if any) shall be determined in accordance with the provisions of Section 2 hereof as if the Participant had remained employed through the Performance Period, but shall be reduced by multiplying the number of Performance Units subject to the Target Award that would otherwise be earned and the total number of Performance Units that would otherwise be earned times a fraction, the numerator of which is the total number of months (with any partial month treated as a whole month) elapsed in the Performance Period as of the date of such termination of employment and the denominator of which is the total number of whole months in the Performance Period. Any such Performance Units earned shall vest on the date Participant’s employment is terminated and the Company shall settle such vested Performance Units in accordance with Section 3 hereof. Any cash dividend equivalents accrued with respect to such earned Performance Units shall be paid in accordance with Section 4 hereof.

7. No Rights as Shareholder . The Participant shall not have voting or other rights as a shareholder of the Company with respect to the Performance Units.

8. Tax Withholding . The Company may make such provisions as are necessary for the withholding of all applicable taxes on all Performance Units vested, earned or settled under this Award, in accordance with Article 15 of the Plan.

9. Ratification of Actions . By accepting this Award or other benefit under the Plan, the Participant and each person claiming under or through him shall be conclusively deemed to

have indicated the Participant’s acceptance and ratification of, and consent to, any action taken under the Plan or the Award by IDACORP, Inc.

10. Notices . Any notice hereunder to IDACORP, Inc. shall be addressed to its office at 1221 West Idaho Street, Boise, Idaho 83702; Attention: Corporate Secretary, and any notice hereunder to the Participant shall be addressed to him or her at the address specified on the Performance Unit Award Agreement, subject to the right of either party to designate at any time hereafter in writing some other address.

11. Definitions . Capitalized terms not otherwise defined herein shall have the meanings given them in the Plan.

12. Governing Law and Severability . To the extent not preempted by Federal law, the Performance Unit Award Agreement will be governed by and construed in accordance with the laws of the State of Idaho, without regard to conflicts of law provisions. In the event any provision of the Performance Unit Award Agreement shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Performance Unit Award Agreement, and the Performance Unit Award Agreement shall be construed and enforced as if the illegal or invalid provision had not been included.

13. Clawback . All Shares paid out to the Participant under the Performance Unit Award Agreement are subject to recoupment by the Company under the terms of the IDACORP Clawback Policy attached hereto as Exhibit A.

14. Additional Information . Please see Exhibit B for additional information regarding the Performance Units and related matters.

Exhibit A

CLAWBACK POLICY

If the Board of Directors determines that a current or former executive officer has engaged in fraud, willful misconduct, gross negligence or violation of Company policy that caused or otherwise contributed to the need for a material restatement of the Company’s financial results, the Compensation Committee will review all performance-based compensation awarded to or earned by that executive officer on the basis of performance during fiscal periods materially affected by the restatement. This would include annual cash incentive/bonus awards and all forms of equity-based compensation. If, in the Committee’s view, the performance-based compensation would have been materially lower if it had been based on the restated results, the Committee will, to the extent permitted by applicable law, seek recoupment from that executive officer of any portion of such performance-based compensation as it deems appropriate after a review of all relevant facts and circumstances.

In determining whether to recover a payment, the Committee shall take into account such considerations as it deems appropriate, including whether the assertion of a claim may violate applicable law or prejudice the interests of the Company in any related proceeding or investigation, the passage of time since the occurrence of the act in respect of the applicable fraud or intentional illegal conduct, and the cost of the recovery process versus the amount to be recovered. The Committee shall have sole discretion in determining whether an executive officer’s conduct has or has not met any particular standard of conduct under law or Company policy.

This policy will apply to new performance-based awards granted after the adoption of the policy. The policy will be updated to conform to the final clawback regulations adopted by the SEC pursuant to the Dodd-Frank Act.

EX.A.

Exhibit B

Dear Participant -

A copy of the 2000 IDACORP, Inc. Long Term Incentive and Compensation Plan (“LTIP”) and supplemental information is available on the Certent Participant Portal.

This document constitutes part of a prospectus covering securities that have been registered under the Securities Act of 1933.

EX.B.

Exhibit 10.44

IDACORP, Inc.

2000 LONG-TERM INCENTIVE AND COMPENSATION PLAN

PERFORMANCE UNIT AWARD AGREEMENT

Cumulative Earnings Per Share

_____________, 20__

[[FIRSTNAME]] [[LASTNAME]]



Date of Grant:	______________, 20__
Number of Performance Units (the “Target Award”):	[[SHARESGRANTED]]
Maximum Number of Additional Performance Units:	[[SHARESGRANTED]]
Performance Period:	_________, 20__ through _________, 20__
Performance Goal:	Cumulative diluted earnings per share (“CEPS”) for the Performance Period, as reported on the Company’s audited financial statements



Vesting Date:	To the extent the Performance Goal is met or exceeded, vesting of earned Performance Units subject to the Award (if any) shall occur upon completion of the Performance Period, with settlement as soon as administratively practicable in the calendar year following the Performance Period, but no later than March 15.
Dividend Equivalents:	Dividend equivalents are accrued throughout the Performance Period and paid as soon as administratively practicable, but no later than March 15 of the calendar year following the Performance Period, with respect to Performance Units subject to the Target Award that are earned and any additional Performance Units that are earned.

THESE PERFORMANCE UNITS ARE SUBJECT TO FORFEITURE AS PROVIDED IN ANNEX A AND THE PLAN.

Further terms and conditions of the Award are set forth in Annex A hereto, which is an integral part of this Performance Unit Award Agreement.

All terms, provisions and conditions applicable to the Award set forth in the Plan and not set forth herein are hereby incorporated by reference herein. To the extent any provision hereof is inconsistent with the Plan, the Plan will govern. The Participant hereby acknowledges receipt of a copy of this Performance Unit Award Agreement including Annex A hereto and a copy of the Plan and agrees to be bound by all the terms and provisions hereof and thereof.

IDACORP, Inc.

By: [[SIGNATURE]]

________________________________

[[FIRSTNAME]] [[LASTNAME]]

Agreed :

[[SIGNATURE]]

_________________________________

[[FIRSTNAME]] [[LASTNAME]]

Address:

[[RESADDR1]] [[RESADDR2]]

[[RESCITY]], [[RESSTATEORPROV]] [[RESPOSTALCODE]]

Attachment: Annex A

ANNEX A

IDACORP, Inc.

2000 LONG-TERM INCENTIVE AND COMPENSATION PLAN

PERFORMANCE UNIT AWARD AGREEMENT

Cumulative Earnings Per Share

It is understood and agreed that the Award of Performance Units evidenced by the Performance Unit Award Agreement to which this is annexed is subject to the following additional terms and conditions:


2.	Performance Goal and Determination of Number of Performance Units Earned .

The number of Performance Units earned, if any, for the Performance Period shall be determined in accordance with the following formula:

# of Units = Payout Percentage X Target Award

The “Payout Percentage” is based on the Company’s cumulative diluted earnings per share (“CEPS”) for the Performance Period as set forth in the table below:

CEPS Table and Method of Calculation:



CEPS for Performance Period	Payout Percentage (% of Target Award)
$___.__ (“maximum”) or higher	___%
$___.__ (“target”)	___%
$___.__ (“threshold”)	___%
Less than $___.__	___%

Performance results between threshold and target, and target and maximum, will be interpolated.

The total number of Performance Units earned shall be rounded to the nearest whole number of Performance Units, with (.5) rounded up.

5. Forfeiture and Transfer Restrictions .


A.	Forfeiture Restrictions . Except as provided otherwise in Section 6 hereof, if the Participant’s employment is terminated during the Performance Period, Performance Units shall be forfeited as of the date of termination.


B.	Transfer Restrictions . Performance Units may not be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated during the Performance Period.

the Performance Period as of the date of such termination of employment and the denominator of which is the total number of whole months in the Performance Period. Any such Performance Units earned shall vest on the date Participant’s employment is terminated and the Company shall settle such vested Performance Units in accordance with Section 3 hereof. Any cash dividend equivalents accrued with respect to such earned Performance Units shall be paid in accordance with Section 4 hereof.

7. No Rights as Shareholder . The Participant shall not have voting or other rights as a shareholder of the Company with respect to the Performance Units.

9. Ratification of Actions . By accepting this Award or other benefit under the Plan, the Participant and each person claiming under or through him shall be conclusively deemed to have indicated the Participant’s acceptance and ratification of, and consent to, any action taken under the Plan or the Award by IDACORP, Inc.

11. Definitions . Capitalized terms not otherwise defined herein shall have the meanings given them in the Plan.

14. Additional Information . Please see Exhibit B for additional information regarding the Performance Units and related matters.

Exhibit A

CLAWBACK POLICY

EX.A.

Exhibit B

Dear Participant -

A copy of the 2000 IDACORP, Inc. Long Term Incentive and Compensation Plan (“LTIP”) and supplemental information is available on the Certent Participant Portal.

This document constitutes part of a prospectus covering securities that have been registered under the Securities Act of 1933.

EX.B.

Exhibit 10.51

IDACORP, Inc. and Idaho Power Company Compensation for

Non-Employee Directors of the Board of Directors

(Effective January 1, 2017)

All directors of IDACORP also serve as directors of Idaho Power. The fees and other compensation discussed below are for service on both boards. Employee directors receive no compensation for service on the boards.



Form of Fee	Amount
Base Board Annual Retainer	$	65,000

Base Committee Annual Retainers ⁽¹⁾
Audit Committee	12,000
Compensation Committee	6,000
Corporate Governance and Nominating Committee	6,000
Executive Committee	3,000

Additional Chair Annual Retainers
Chairperson of the Board of Directors	100,000
Chair of the Audit Committee	12,500
Chair of the Compensation Committee	10,000
Chair of the Corporate Governance and Nominating Committee	7,500

Annual Stock Awards	100,000


(1) The Chairperson of the Board of Directors does not receive base committee retainers.

Deferral Arrangements

Directors may defer all or a portion of their annual IDACORP, Idaho Power, IDACORP Financial Services, Inc., and Ida-West Energy retainers and meeting fees and receive a lump-sum payment of all amounts deferred with interest or a series of up to 10 equal annual payments after they separate from service with IDACORP and Idaho Power. Any cash fees that were deferred before 2009 for service as a member of the board of directors are credited with the preceding month’s average Moody’s Long-Term Corporate Bond Yield for utilities, or the Moody’s Rate, plus 3%, until January 1, 2019 when the interest rate will change to the Moody’s Rate. All cash fees that are deferred for service as a member of the board of directors after January 1, 2009 are credited with interest at the Moody’s Rate. Interest is calculated on a pro rata basis each month using a 360-day year and the average Moody’s Rate for the preceding month.

Directors may also defer their annual stock awards, which are then held as deferred stock units with dividend equivalents reinvested in additional deferred stock units. Upon separation from service with IDACORP and Idaho Power, directors will receive either a lump-sum distribution or a series of up to 10 equal annual installments. Upon a change in control the directors’ deferral accounts will be distributed to each participating director in a lump sum. The distributions will be in shares of IDACORP common stock, with each deferred stock unit equal to one share of IDACORP common stock and any fractional shares paid in cash.

Exhibit 10.61

FIRST AMENDMENT

TO THE EMPLOYEE SAVINGS PLAN OF

IDAHO POWER COMPANY

The Employee Savings Plan of Idaho Power Company, as amended and restated effective January 1, 2016 (the “Plan”) is further amended, effective December 1, 2016, as set forth below.

1. Section 3.5 is amended to read as follows:

“Rollover Contributions shall be permitted, subject to the provisions of this Section. The Administrator may direct the Trustee to accept, in accordance with procedures approved by the Administrator, all or part of an Eligible Rollover Distribution for the benefit of a Participant from (i) the Participant, (ii) another Qualified Plan, including, in a trustee-to-trustee transfer, After-Tax Contributions or Roth Deferrals to that plan, (iii) an annuity contract described in Code section 403(b), (iv) an individual retirement account (except a Roth IRA) or annuity as defined in Code sections 408(a) or 408(b) that is eligible to be rolled over and otherwise would be includible in gross income, or (v) an eligible plan under Code section 457(b) which is maintained by a state, political subdivision of a state, or any agency or instrumentality of a state or political subdivision of a state. The approved procedures shall require that the Administrator reasonably conclude that any accepted Eligible Rollover Distribution is a valid rollover contribution in accordance with Treasury regulations and guidance.”

2. Section 4.4.2(b) is amended to read as follows:

“The Administrator shall provide the Trustee with valuations for Investment Funds which are not liquid or publicly traded, which valuations will account for the allocation of income or loss.”

3. Section 5.5 is amended to read as follows:

“The fair market value of the total net assets comprising the Trust Fund and of each Investment Fund will be determined as of the close of business on each Valuation Date. Each such valuation will be made in accordance with the terms of the Trust Agreement.”

4. Section 8.2 is amended to read as follows:

“If a Participant is also a participant in another Qualified Plan which is sponsored by an Acquisition Business or Controlled Group Member, the Participant may direct the Trustee, subject to the approval of the Administrator, to accept from such Qualified Plan an amount representing such Participant’s interest in such plan, to be held by the Trustee subject to all of the terms and conditions of the Plan and Trust Agreement, in the Participant’s Rollover Account; provided, however, that property

other than cash shall not be transferred to the Trustee without the approval of the Administrator and Trustee, and provided, further, that the Administrator may establish such procedures (including but not limited to required notice periods) as the Administrator shall deem appropriate, which must be followed by the Participant as a condition to such a transfer of assets. The Administrator may not approve any transfer to the Plan if such transfer would require the Plan to offer benefits, rights and features not offered under the Plan in order to comply with the requirements of Code section 411(d) and the regulations thereunder. Amounts transferred to the Plan from another Qualified Plan, other than such amounts transferred in a direct rollover transfer within the meaning of Code section 401(a)(31), shall retain all benefits, rights, and features provided under the Qualified Plan and protected under Code section 411(d)(6), except to the extent that such benefits, rights and features may be eliminated under the regulations under Code section 411(d)(6).”

IN WITNESS WHEREOF, the Company has executed this Amendment this 22nd day of November, 2016.

IDAHO POWER COMPANY

By: /s/ Lonnie G. Krawl

Lonnie G. Krawl

Its: Vice President of Human

Resources, Administrative Services

and Chief Information Officer

Exhibit 12.1

IDACORP, Inc.

Consolidated Financial Information

Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges

(Thousands of Dollars)




	Twelve Months Ended
	December 31,
	2016		2015		2014			2013		2012
RATIO OF EARNINGS TO FIXED CHARGES

Earnings, as defined:
Income from continuing operations before income taxes	$	234,517	$	240,235	$	210,526		$	254,520	$	206,992
Adjust for distributed income of equity investees	12,770		1,330		(6,797		)	4,812		7,704
Fixed charges, as below	93,857		93,409		90,012			90,236		87,635
Total earnings, as defined	$	341,144	$	334,974	$	293,741		$	349,568	$	302,331

Fixed charges, as defined:
Interest charges ¹	$	92,229	$	91,978	$	88,265		$	88,695	$	85,799
Rental interest factor	1,628		1,431		1,747			1,541		1,836
Total fixed charges, as defined	$	93,857	$	93,409	$	90,012		$	90,236	$	87,635
Ratio of earnings to fixed charges	3.63x		3.59x		3.26x			3.87x		3.45x

SUPPLEMENTAL RATIO OF EARNINGS TO FIXED CHARGES

Earnings, as defined:
Income from continuing operations before income taxes	$	234,517	$	240,235	$	210,526		$	254,520	$	206,992
Adjust for distributed income of equity investees	12,770		1,330		(6,797		)	4,812		7,704
Supplemental fixed charges, as below	94,075		93,651		90,356			90,741		88,266
Total earnings, as defined	$	341,362	$	335,216	$	294,085		$	350,073	$	302,962

Supplemental fixed charges:
Interest charges ¹	$	92,229	$	91,978	$	88,265		$	88,695	$	85,799
Rental interest factor	1,628		1,431		1,747			1,541		1,836
Supplemental increment to fixed charges ²	218		242		344			505		631
Total supplemental fixed charges	$	94,075	$	93,651	$	90,356		$	90,741	$	88,266
Supplemental ratio of earnings to fixed charges	3.63x		3.58x		3.25x			3.86x		3.43x

¹ FIN 48 interest is not included in interest charges.
² Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.

Exhibit 12.2

Idaho Power Company

Consolidated Financial Information

Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges

(Thousands of Dollars)




	Twelve Months Ended
	December 31,
	2016		2015		2014			2013		2012
RATIO OF EARNINGS TO FIXED CHARGES

Earnings, as defined:
Income from continuing operations before income taxes	$	226,427	$	239,211	$	208,903		$	253,001	$	204,138
Adjust for distributed income of equity investees	12,861		1,060		(7,228		)	4,659		8,509
Fixed charges, as below	93,615		93,164		89,751			89,819		87,162
Total earnings, as defined	$	332,903	$	333,435	$	291,426		$	347,479	$	299,809

Fixed charges, as defined:
Interest charges ¹	$	92,006	$	91,762	$	88,034		$	88,309	$	85,359
Rental interest factor	1,609		1,402		1,717			1,510		1,803
Total fixed charges, as defined	$	93,615	$	93,164	$	89,751		$	89,819	$	87,162
Ratio of earnings to fixed charges	3.56x		3.58x		3.25x			3.87x		3.44x

SUPPLEMENTAL RATIO OF EARNINGS TO FIXED CHARGES

Earnings, as defined:
Income from continuing operations before income taxes	$	226,427	$	239,211	$	208,903		$	253,001	$	204,138
Adjust for distributed income of equity investees	12,861		1,060		(7,228		)	4,659		8,509
Supplemental fixed charges, as below	93,833		93,406		90,095			90,324		87,793
Total earnings, as defined	$	333,121	$	333,677	$	291,770		$	347,984	$	300,440

Supplemental fixed charges:
Interest charges ¹	$	92,006	$	91,762	$	88,034		$	88,309	$	85,359
Rental interest factor	1,609		1,402		1,717			1,510		1,803
Supplemental increment to fixed charges ²	218		242		344			505		631
Total supplemental fixed charges	$	93,833	$	93,406	$	90,095		$	90,324	$	87,793
Supplemental ratio of earnings to fixed charges	3.55x		3.57x		3.24x			3.85x		3.42x

¹ FIN 48 interest is not included in interest charges.
² Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-200399 and 333-211475 on Form S-3 and Registration Statement Nos. 333-65406, 333-125259, and 333-159855 on Form S-8 of our reports dated February 23, 2017 , relating to the consolidated financial statements and financial statement schedules of IDACORP, Inc. (which report expresses an unqualified opinion), and the effectiveness of IDACORP, Inc.'s internal control over financial reporting, appearing in this Annual Report on Form 10-K of IDACORP, Inc. for the year ended December 31, 2016 .

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

February 23, 2017

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-211475-01 on Form S-3 and Registration Statement No. 333-66496 on Form S-8 of our reports dated February 23, 2017 , relating to the consolidated financial statements and financial statement schedule of Idaho Power Company (which report expresses an unqualified opinion), and the effectiveness of Idaho Power Company's internal control over financial reporting, appearing in this Annual Report on Form 10-K of Idaho Power Company for the year ended December 31, 2016 .

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

February 23, 2017

Exhibit 31.1

CERTIFICATION

I, Darrel T. Anderson, certify that:


1.	I have reviewed this Annual Report on Form 10-K of IDACORP, Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	February 23, 2017	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

Exhibit 31.2

CERTIFICATION

I, Steven R. Keen, certify that:


1.	I have reviewed this Annual Report on Form 10-K of IDACORP, Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	February 23, 2017	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial Officer, and Treasurer

Exhibit 31.3

CERTIFICATION

I, Darrel T. Anderson, certify that:


1.	I have reviewed this Annual Report on Form 10-K of Idaho Power Company;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	February 23, 2017	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

Exhibit 31.4

CERTIFICATION

I, Steven R. Keen, certify that:


1.	I have reviewed this Annual Report on Form 10-K of Idaho Power Company;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	February 23, 2017	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial Officer, and Treasurer

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of IDACORP, Inc. (the "Company") on Form 10-K for the year ended December 31, 2016 (the "Report"), I, Darrel T. Anderson, President and Chief Executive Officer of the Company, certify that:


(1)	The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Darrel T. Anderson

Darrel T. Anderson

President and Chief Executive Officer

February 23, 2017

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of IDACORP, Inc. (the "Company") on Form 10-K for the year ended December 31, 2016 (the "Report"), I, Steven R. Keen, Senior Vice President, Chief Financial Officer, and Treasurer of the Company, certify that:


(1)	The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Steven R. Keen

Steven R. Keen

Senior Vice President, Chief Financial Officer, and Treasurer

February 23, 2017

Exhibit 32.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Idaho Power Company (the "Company") on Form 10-K for the year ended December 31, 2016 (the "Report"), I, Darrel T. Anderson, President and Chief Executive Officer of the Company, certify that:


(1)	The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Darrel T. Anderson

Darrel T. Anderson

President and Chief Executive Officer

February 23, 2017

Exhibit 32.4

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Idaho Power Company (the "Company") on Form 10-K for the year ended December 31, 2016 (the "Report"), I, Steven R. Keen, Senior Vice President, Chief Financial Officer, and Treasurer of the Company, certify that:


(1)	The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Steven R. Keen

Steven R. Keen

Senior Vice President, Chief Financial Officer, and Treasurer

February 23, 2017

Exhibit 95.1

Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act

Idaho Power is the parent company of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines coal at the Bridger Coal Mine and processing facility (Mine) near Rock Springs, Wyoming. IERCo owns a one-third interest in BCC. The Mine is comprised of the Bridger surface and underground operations. Day-to-day operation and management of coal mining and processing operations at the Mine are conducted through IERCo's joint venture partner. Operation of the Mine is regulated by the Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (Mine Safety Act). MSHA inspects the Mine on a regular basis and may issue citations, notices, orders, or any combination thereof, when it believes a violation has occurred under the Mine Safety Act. Monetary penalties are assessed by MSHA for citations. The severity and assessment of penalties may be reduced or, in some cases, dismissed through the contest and appeal process. Amounts are reported regardless of whether BCC has challenged or appealed the matter.

The table below summarizes the number of citations, notices, and orders issued, and penalties assessed, by MSHA for the Mine under the indicated provisions of the Mine Safety Act, and other data for the Mine, during the year ended December 31, 2016 . Legal actions pending before the Federal Mine Safety and Health Review Commission (FMSHRC) are as of December 31, 2016 .



			Twelve-month period ended December 31, 2016 (unaudited)
			(surface)		(underground)
Mine Safety Act Citations and Orders:
	Section 104(a) Significant & Substantial Citations ⁽¹⁾		5		37
	Section 104(b) Orders ⁽²⁾		—		—
	Section 104(d) Citations & Orders ⁽³⁾		—		—
	Section 107(a) Imminent Danger Orders ⁽⁴⁾		—		—

Total Value of Proposed MSHA Assessments (in thousands)		$	12	$	74
Legal Actions Pending ⁽⁵⁾			5		4
Legal Actions Issued During Period			3		9
Legal Actions Closed During Period			4		10
Number of Fatalities			—		—
_______________
⁽¹⁾ For alleged violations of a mandatory mining safety standard or regulation where such violation contributed to a discrete safety hazard and there exists a reasonable likelihood that the hazard will result in an injury or illness and there is a reasonable likelihood that such injury will be of a reasonably serious nature.
⁽²⁾ For alleged failure to totally abate the subject matter of a Mine Safety Act Section 104(a) citation within the period specified in the citation or as subsequently extended.
⁽³⁾ For an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.
⁽⁴⁾ The existence of any condition or practice in a coal or other mine that could reasonably be expected to cause death or serious physical harm if normal mining operations were permitted to proceed in the area before such condition or practice is eliminated.
⁽⁵⁾ For the surface mine, two of the pending legal actions as of December 31, 2016 were categorized as contests of citations or orders under Subpart B of the FMSHRC Procedural Rules, two of the pending legal actions were categorized as contests of proposed civil penalties for violations contained in a citation or order under Subpart C of the FMSHRC Procedural Rules, and one of the pending legal actions was categorized as a discharge, discrimination or interference under Subpart E of the FMSHRC Procedural Rules. For the underground mine, the four pending legal actions were categorized as contests of proposed civil penalties for violations contained in a citation or order under Subpart C of the FMSHRC Procedural Rules.

For the year ended December 31, 2016 , the Mine did not receive written notice from MSHA of (i) a flagrant violation under Section 110(b)(2) of the Mine Safety Act; (ii) a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards under Section 104(e) of the Mine Safety Act; or (iii) the potential to have such a pattern.