10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

☑	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2016
	Or
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-32347

ORMAT TECHNOLOGIES, INC.

(Exact name of registrant as specified in its charter)

DELAWARE	88-0326081
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

6225 Neil Road, Reno, Nevada 89511-1136

(Address of principal executive offices, including zip code)

Registrant’s telephone number, including area code:

(775) 356-9029

(Registrant’s telephone number, including area code)

Securities Registered Pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock $0.001 Par Value	New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes ☐     No ☑

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes ☐     No ☑

Indicate by check mark whether the registrant (1) has 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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ☑     No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ☑     No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s 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.  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large  accelerated filer ☑	Accelerated filer ☐	Non-accelerated filer ☐	Smaller  reporting company ☐
	(Do not check if  a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ☐     No ☑

As of June 30, 2016, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $1,418,095,165 based on the closing price as reported on the New York Stock Exchange.Indicate the number of shares outstanding of each of the registrant’s classes of common stock as of the latest practicable date: As of February 27, 2017, the number of outstanding shares of common stock, par value $0.001 per share was 49,667,340.

Documents incorporated by reference: Part III (Items 10, 11, 12, 13 and 14) incorporates by reference portions of the Registrant’s Proxy Statement for its Annual Meeting of Stockholders, which will be filed not later than 120 days after December 31, 2016.

ORMAT TECHNOLOGIES, INC.

FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2016

TABLE OF CONTENTS

		Page No
PART I
ITEM 1.	BUSINESS	6
ITEM 1A.	RISK FACTORS	72
ITEM 1B.	UNRESOLVED STAFF COMMENTS	89
ITEM 2.	PROPERTIES	89
ITEM 3.	LEGAL.PROCEEDINGS	89
ITEM 4.	MINE SAFETY DISCLOSURES	90
PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	91
ITEM 6.	SELECTED FINANCIAL DATA	92
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	95
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	131
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	132
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	205
ITEM 9A.	CONTROLS AND PROCEDURES	205
ITEM 9B.	OTHER INFORMATION	205
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	206
ITEM 11.	EXECUTIVE COMPENSATION	206
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	206
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	206
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	206
PART II
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	207
SIGNATURES		208

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Glossary of Terms
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
Term	Definition
Amatitlan Loan	$42,000,000 in initial aggregate principal amount borrowed by our subsidiary Ortitlan Limitada from Banco Industrial S.A. and Westrust Bank (International) Limited.
AMM	Administrador del Mercado Mayorista (administrator of the wholesale market — Guatemala)
ARRA	American Recovery and Reinvestment Act of 2009
Auxiliary Power	The power needed to operate a geothermal power plant’s auxiliary equipment such as pumps and cooling towers
Availability	The ratio of the time a power plant is ready to be in service, or is in service, to the total time interval under consideration, expressed as a percentage, independent of fuel supply (heat or geothermal) or transmission accessibility
Balance of Plant equipment	Power plant equipment other than the generating units including items such as transformers, valves, interconnection equipment, cooling towers for water cooled power plants, etc.
BESS	Battery Energy Storage Systems
BLM	Bureau of Land Management of the U.S. Department of the Interior
BOT	Build, operate and transfer
Capacity	The maximum load that a power plant can carry under existing conditions, less auxiliary power
Capacity Factor	The ratio of the average load on a generating resource to its generating capacity during a specified period of time, expressed as a percentage
CARB	California Air Resources Board
CFE	Comision Federal de Electricidad
C&I	Refers to the Commercial and Industrial sectors, excluding residential
CNE	National Energy Commission of Honduras
CNEE	National Electric Energy Commission of Guatemala
COD	Commercial Operation Date
Company	Ormat Technologies, Inc., a Delaware corporation, and its consolidated subsidiaries
COSO	Committee of Sponsoring Organizations of the Treadway Commission
CPI	Consumer Price Index
CPUC	California Public Utilities Commission
Cyrq	Cyrq Energy, Inc.
DEG	Deutsche Investitions-und Entwicklungsgesellschaft mbH
DFIs	Development Finance Institutions
DOE	U.S. Department of Energy
DOGGR	California Division of Oil, Gas, and Geothermal Resources
DSCR	Debt Service Coverage Ratio
EBITDA	Earnings before interest, taxes, depreciation and amortization
EDF	Electricite de France S.A.
EGS	Enhanced Geothermal Systems
EIB	European Investment Bank
ENEE	Empresa Nacional de Energía Eléctrica
Enthalpy	The total energy content of a fluid; the heat plus the mechanical energy content of a fluid (such as a geothermal brine), which, for example, can be partially converted to mechanical energy in an Organic Rankine Cycle.

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Term	Definition
EPA	U.S. Environmental Protection Agency
EPC	Engineering, procurement and construction
EPS	Earnings per share
ERC	Kenyan Energy Regulatory Commission
ERCOT	Electric Reliability Council of Texas, Inc.
ESC	Energy Sales Contract
Exchange Act	U.S. Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	U.S. Federal Energy Regulatory Commission
FIT	Feed-in Tariff
FPA	U.S. Federal Power Act, as amended
GAAP	Generally accepted accounting principles
GCCU	Geothermal Combined Cycle Unit
GDC	Geothermal Development Company
GEA	Geothermal Energy Association
Geothermal Power Plant	The power generation facility and the geothermal field
Geothermal Steam Act	U.S. Geothermal Steam Act of 1970, as amended
GHG	Greenhouse gas
GNP	Gross National Product
HELCO	Hawaii Electric Light Company
IFC	International Finance Corporation
IID	Imperial Irrigation District
ILA	Israel Land Administration
INDE	Instituto Nacional de Electrification
IPPs	Independent Power Producers
ISO	International Organization for Standardization
ITC	Investment tax credit
ITC Cash Grant	Payment for Specified Renewable Energy property in lieu of Tax Credits under Section 1603 of the ARRA
JBIC	Japan Bank for International Cooperation
John Hancock	John Hancock Life Insurance Company (U.S.A.)
JPM	JPM Capital Corporation
KenGen	Kenya Electricity Generating Company Ltd.
Kenyan Energy Act	Kenyan Energy Act, 2006
KETRACO	Kenya Electricity Transmission Company Limited
KLP	Kapoho Land Partnership
KPLC	Kenya Power and Lighting Co. Ltd.
kVa	Kilovolt-ampere
kW	Kilowatt - A unit of electrical power that is equal to 1,000 watts
kWh	Kilowatt hour(s), a measure of power produced
LCOE	Levelized Costs of Energy
Mammoth Pacific	Mammoth-Pacific, L.P.
MACRS	Modified Accelerated Cost Recovery System
MEMR	Ministry of Energy and Mineral Resources
MIGA	Multilateral Investment Guarantee Agency, a member of the World Bank Group
MW	Megawatt - One MW is equal to 1,000 kW or one million watts
MWh	Megawatt hour(s), a measure of energy produced

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Term	Definition
NBPL	Northern Border Pipe Line Company
NIS	New Israeli Shekel
NGI	Natural Gas-California SoCal-NGI Natural Gas price index
NV Energy	NV Energy, Inc.
NYSE	New York Stock Exchange
NYISO	New York Independent System Operator, Inc.
OEC	Ormat Energy Converter
OFC	Ormat Funding Corp., a wholly owned subsidiary of the Company
OFC Senior Secured Notes	$190,000,000 8.25% Senior Secured Notes, due 2020 issued by OFC
OFC 2	OFC 2 LLC, a wholly owned subsidiary of the Company
OFC 2 Senior Secured Notes	Up to $350,000,000 Senior Secured Notes, due 2034 issued by OFC 2
OMPC	Ormat Momotombo Power Company, a wholly owned subsidiary of the Company
OPC	OPC LLC, a consolidated subsidiary of the Company
OPC Transaction	Financing transaction involving four of our Nevada power plants in which institutional equity investors purchased an interest in our special purpose subsidiary that owns such plants.
OPIC	Overseas Private Investment Corporation
OrCal	OrCal Geothermal Inc., a wholly owned subsidiary of the Company
OrCal Senior Secured Notes	$165,000,000 6.21% Senior Secured Notes, due 2020 issued by OrCal
Organic Rankine Cycle	A process in which an organic fluid such as a hydrocarbon or fluorocarbon (but not water) is boiled in an evaporator to generate high pressure vapor. The vapor powers a turbine to generate mechanical power. After the expansion in the turbine, the low pressure vapor is cooled and condensed back to liquid in a condenser. A cycle pump is then used to pump the liquid back to the vaporizer to complete the cycle. The cycle is illustrated in the figure below:
Ormat International	Ormat International Inc., a wholly owned subsidiary of the Company
Ormat Nevada	Ormat Nevada Inc., a wholly owned subsidiary of the Company
Ormat Systems	Ormat Systems Ltd., a wholly owned subsidiary of the Company
ORPD	ORPD LLC, a holding company subsidiary of the Company in which Northleaf Geothermal Holdings, LLC holds a 36.75% equity interest
ORPD Transaction	Financing transaction involving the Puna complex and Don A. Campbell, OREG 1, OREG 2 and OREG 3 power plants in which Northleaf Geothermal Holdings, LLC purchased an equity interest in our special purpose subsidiary that owns such plants.
OrPower 4	OrPower 4 Inc., a wholly owned subsidiary of the Company
Ortitlan	Ortitlan Limitada, a wholly owned subsidiary of the Company
ORTP	ORTP, LLC, a consolidated subsidiary of the Company

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Term	Definition
ORTP Transaction	Financing transaction involving power plants in Nevada and California in which an institutional equity investor purchased an interest in our special purpose subsidiary that owns such plants.
Orzunil	Orzunil I de Electricidad, Limitada, a wholly owned subsidiary of the Company
PEC	Portfolio Energy Credits
PG&E	Pacific Gas and Electric Company
PGV	Puna Geothermal Venture, a wholly owned subsidiary of the Company
PJM	PJM Interconnection, L.L.C.
PLN	PT Perusahaan Listrik Negara
Power plant equipment	Interconnection equipment, cooling towers for water cooled power plant, etc., including the generating units
PPA	Power purchase agreement
ppm	Part per million
PTC	Production tax credit
PUA	Israeli Public Utility Authority
PUCH	Public Utilities Commission of Hawaii
PUCN	Public Utilities Commission of Nevada
PUHCA	U.S. Public Utility Holding Company Act of 1935
PUHCA 2005	U.S. Public Utility Holding Company Act of 2005
PURPA	U.S. Public Utility Regulatory Policies Act of 1978
Qualifying Facility(ies)	Certain small power production facilities are eligible to be “Qualifying Facilities” under PURPA, provided that they meet certain power and thermal energy production requirements and efficiency standards. Qualifying Facility status provides an exemption from PUHCA 2005 and grants certain other benefits to the Qualifying Facility
RAM	Renewable Auction Mechanism
REC	Renewable Energy Credit
REG	Recovered Energy Generation
RGGI	Regional Greenhouse Gas Initiative
RPM	Revolutions Per Minute
RPS	Renewable Portfolio Standards
RTO	Regional Transmission Organization
SaaS	Software as a Service
SCADA	Supervisory Control and Data Acquisition
SCPPA	Southern California Public Power Authority
SEC	U.S. Securities and Exchange Commission
Securities Act	U.S. Securities Act of 1933, as amended
Senior Unsecured Bonds	7% Senior Unsecured Bonds Due 2017 issued by the Company
SO#4	Standard Offer Contract No. 4
Solar PV	Solar photovoltaic
SOX Act	Sarbanes-Oxley Act of 2002
Southern California Edison	Southern California Edison Company
SPE(s)	Special purpose entity(ies)
SRAC	Short Run Avoided Costs
Union Bank	Union Bank, N.A.
U.S.	United States of America
U.S. Treasury	U.S. Department of the Treasury
WHOH	Waste Heat Oil Heaters

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Cautionary Note Regarding Forward-Looking Statements

This annual report includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future, including such matters as our projections of annual revenues, expenses and debt service coverage with respect to our debt securities, future capital expenditures, business strategy, competitive strengths, goals, development or operation of generation assets, market and industry developments and the growth of our business and operations, are forward-looking statements. When used in this annual report, the words “may”, “will”, “could”, “should”, “expects”, “plans”, “anticipates”, “believes”, “estimates”, “predicts”, “projects”, “potential”, or “contemplate” or the negative of these terms or other comparable terminology are intended to identify forward-looking statements, although not all forward-looking statements contain such words or expressions. The forward-looking statements in this annual report are primarily located in the material set forth under the headings Item 1 — “Business” contained in Part I of this annual report, Item 1A — “Risk Factors” contained in Part I of this annual report, Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in Part II of this annual report, and “Notes to Financial Statements” contained in Item 8 — “Financial Statements and Supplementary Data” contained in Part II of this annual report, but are found in other locations as well. These forward-looking statements generally relate to our plans, objectives and expectations for future operations and are based upon management’s current estimates and projections of future results or trends. Although we believe that our plans and objectives reflected in or suggested by these forward-looking statements are reasonable, we may not achieve these plans or objectives. You should read this annual report completely and with the understanding that actual future results and developments may be materially different from what we expect due to a number of risks and uncertainties, many of which are beyond our control. Other than as required by law, we will not update forward-looking statements even though our situation may change in the future.

Specific factors that might cause actual results to differ from our expectations include, but are not limited to:

● significant considerations, risks and uncertainties discussed in this annual report;

● geothermal resource risk (such as the heat content, useful life and geological formation of the reservoir);

● operating risks, including equipment failures and the amounts and timing of revenues and expenses;

● financial market conditions and the results of financing efforts;

● the impact of fluctuations in oil and natural gas prices on the energy price component under certain of our PPAs;

● risks and uncertainties with respect to our ability to implement strategic goals or initiatives in segments of the clean energy industry or new or additional geographic focus areas;

● environmental constraints on operations and environmental liabilities arising out of past or present operations, including the risk that we may not have, and in the future may be unable to procure, any necessary permits or other environmental authorizations;

● construction or other project delays or cancellations;

● political, legal, regulatory, governmental, administrative and economic conditions and developments in the United States and other countries in which we operate and, in particular, the impact of recent and future federal, state and local regulatory proceedings and changes, including legislative and regulatory initiatives regarding deregulation, restructuring and re-regulation of the electric utility industry, public policies and government incentives that support renewable energy and enhance the economic feasibility of our projects at the federal and state level in the United States and elsewhere, and carbon-related legislation;

● the enforceability of long-term PPAs for our power plants;

● contract counterparty risk;

● weather and other natural phenomena including earthquakes, volcanic eruption, drought and other natural disasters;

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● changes in environmental and other laws and regulations to which our company is subject, as well as changes in the application of existing laws and regulations;

● current and future litigation;

● our ability to successfully identify, integrate and complete acquisitions;

● competition from other geothermal energy projects and new geothermal energy projects developed in the future, and from alternative electricity producing technologies;

● market or business conditions and fluctuations in demand for energy or capacity in the markets in which we operate;

● the direct or indirect impact on our company’s business of various forms of hostilities including the threat or occurrence of war, terrorist incidents or cyber-attacks or responses to such threatened or actual incidents or attacks, including the effect on the availability of and premiums on insurance;

● our new strategic plan to expand our geographic markets, customer base and product and service offerings may not be implemented as currently planned or may not achieve our goals as and when implemented;

● development and construction of Solar PV and energy storage projects, if any, may not materialize as planned;

● the effect of and changes in current and future land use and zoning regulations, residential, commercial and industrial development and urbanization in the areas in which we operate; and

● other uncertainties which are difficult to predict or beyond our control and the risk that we may incorrectly analyze these risks and forces or that the strategies we develop to address them may be unsuccessful.

PART I

ITEM 1. BUSINESS

Certain Definitions

Unless the context otherwise requires, all references in this annual report to “Ormat”, “the Company”, “we”, “us”, “our company”, “Ormat Technologies”, or “our” refer to Ormat Technologies, Inc. and its consolidated subsidiaries. A glossary of certain terms and abbreviations used in this annual report appears at the beginning of this report.

Overview

We are a leading vertically integrated company that is currently primarily engaged in the geothermal and recovered energy power business. With the objective of becoming a leading global provider of renewable energy, we focus on several key initiatives, under our new strategic plan, as described below.

We design, develop, build, sell, own, and operate clean, environmentally friendly geothermal and recovered energy-based power plants, usually using equipment that we design and manufacture.

6

Our geothermal power plants include both power plants that we have built and power plants that we have acquired, while we have built all of our recovered energy-based plants. We currently conduct our business activities in two business segments:

● The Electricity segment — in this segment we develop, build, own and operate geothermal and recovered energy-based power plants in the U.S. and geothermal power plants in other countries around the world, and sell the electricity they generate and in the future, we plan to include services and other revenues derived from activity in the demand response and storage market as described below; and

● The Product segment — in this segment we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation and remote power units and provide services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy-based power plants and in the future, other power generating units such as Solar PV and energy storage.

We intend to expand our operation to include demand response, energy management and storage. We recently signed an agreement to acquire substantially all of the business and assets of Viridity Energy, Inc. (VEI), a privately held Philadelphia-based company with nearly a decade of expertise and leadership in demand response, energy management and storage. The acquired assets will be owned by our newly established wholly owned subsidiary, Viridity Energy Solutions Inc. (Viridity). The acquisition, which is expected to close in early 2017, will mark Ormat’s entry into the growing energy storage and demand response markets. We intend to use Viridity to accelerate long-term growth, expand our market presence, and further develop Viridity’s demand response VPower™ software platform and energy storage services. We plan to continue to provide services and products to existing customers of the acquired business, while expanding into new geographies and targeting a broader potential customer base.

The map below shows our worldwide portfolio of operating geothermal and recovered energy power plants as of February 27, 2017.

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The charts below show the relative contributions of the Electricity segment and the Product segment to our consolidated revenues and the geographical breakdown of our segment revenues for our fiscal year ended December 31, 2016. Additional information concerning our segment operations, including year-to-year comparisons of revenues, the geographical breakdown of revenues, cost of revenues, results of operations, and trends and uncertainties is provided below in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8 — “Financial Statements and Supplementary Data”.

The following chart sets forth a breakdown of our revenues for each of the years ended December 31, 2016 and 2015:

Segment Contribution to Revenues

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The following chart sets forth the geographical breakdown of revenues attributable to our Electricity and Product segments for each of the years ended December 31, 2016 and 2015:

Geographical Breakdown of the Electricity Segment Revenues

Geographical Breakdown of the Product Segment Revenues

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Most of the power plants that we currently own or operate produce electricity from geothermal energy sources. Geothermal energy is a clean, renewable and generally sustainable form of energy derived from the natural heat of the earth. Unlike electricity produced by burning fossil fuels, electricity produced from geothermal energy sources is produced without emissions of certain pollutants such as nitrogen oxide, and with far lower emissions of other pollutants such as carbon dioxide. As a result, electricity produced from geothermal energy sources contributes significantly less to global warming and local and regional incidences of acid rain than energy produced by burning fossil fuels. In addition, compared to power plants that utilize other renewable energy sources, such as wind or solar, geothermal power plants are generally available all the time and can provide base load electricity services. In addition, they can be custom built to provide a range of services such as baseload, voltage regulation, reserves and flexible capacity. Geothermal energy is also an attractive alternative to other sources of energy as part of a national diversification strategy to avoid dependence on any one energy source or politically sensitive supply sources.

In addition to our geothermal energy business, we manufacture products that produce electricity from recovered energy or so-called “waste heat”. We also construct, own, and operate recovered energy-based power plants. Recovered energy comes from residual heat that is generated as a by-product of gas turbine-driven compressor stations, solar thermal units and a variety of industrial processes, such as cement manufacturing. Such residual heat, which would otherwise be wasted, may be captured in the recovery process and used by recovered energy power plants to generate electricity without burning additional fuel and without additional emissions.

Since 2015, we have begun to implement a number of elements of our new multi-year strategic plan.  We expect the plan to evolve over time in response to market conditions and other factors.  At this time however, we expect that our primary focus will be as follows:

● Expand our geothermal geographical reach.  While we continue to evaluate opportunities worldwide, we currently see Mexico, Honduras, Chile, Indonesia, Turkey, Kenya, Guatemala, Djibouti and Ethiopia as very attractive geothermal markets for us.  We are actively looking at ways to expand our presence in those countries. In addition, we are looking to expand and accelerate growth through acquisition activities globally as we recently did by acquiring a geothermal power plant in Guadeloupe Island in the Caribbean.

● Expand into new technologies.We ultimately hope to be able to leverage our technological capabilities over a variety of renewable energy platforms, including solar power generation and energy storage.  Initially, however, we expect that our focus will be on expanding our core geothermal competencies, such as expanding into steam geothermal generation equipment and facilities.  For example, we announced a new collaboration with Toshiba described below, which we anticipate may facilitate joint development of geothermal systems consisting of Ormat’s binary system and Toshiba’s flash system, among other things. We may acquire companies with technological and integration capabilities we do not currently have, or develop new technology ourselves, where we can effectively leverage our expertise to implement this part of our strategic plan. As an example, we recently acquired the business and assets of VEI, a company with nearly a decade of expertise and leadership in demand response, energy management and storage.

● Expand our customer base.We are evaluating a number of strategies for expanding our customer base to C&I customers.  In the near term, however, we expect that a majority of our revenues will continue to be generated as they currently are, with our traditional electrical utility customer base for the Electricity segment and our on-going business development efforts for new customers for our Product segment.

While we believe that long-term growth can be realized through our transformational efforts over time, there is no assurance if and when we will meet our objective to become a leading global provider of renewable energy or that such efforts will result in long-term growth. To be clear, we see these new initiatives as incremental measures to enhance shareholder value.  While we implement the plan, we expect to continue, and expand, through organic growth, acquisitions, and other measures, our current business lines both in the Electricity and Product segments as well as other business lines as described above.

Company Contact and Sources of Information

We file annual, quarterly and periodic reports, proxy statements and other information with the SEC. You may obtain and copy any document we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington D.C. 20549. You may obtain information on the operation of the SEC’s Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and other information statements, and other information regarding issuers that file electronically with the SEC. Our SEC filings are accessible via the internet at that website.

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Our reports on Form 10-K, 10-Q and 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available through our website at www.ormat.com for downloading, free of charge, as soon as reasonably practicable after these reports are filed with the SEC. Our Code of Business Conduct and Ethics, Code of Ethics Applicable to Senior Executives, Audit Committee Charter, Corporate Governance Guidelines, Nominating and Corporate Governance Committee Charter, Compensation Committee Charter, and Insider Trading Policy, as amended, are also available at our website address mentioned above. If we make any amendments to our Code of Business Conduct and Ethics or Code of Ethics Applicable to Senior Executives or grant any waiver, including any implicit waiver, from a provision of either code applicable to our Chief Executive Officer, Chief Financial Officer or principal accounting officer requiring disclosure under applicable SEC rules, we intend to disclose the nature of such amendment or waiver on our website. The content of our website, however, is not part of this annual report.

You may request a copy of our SEC filings, as well as the foregoing corporate documents, at no cost to you, by writing to the Company address appearing in this annual report or by calling us at (775) 356-9029.

Our Power Generation Business (Electricity Segment)

Power Plants in Operation

The table below summarizes certain key non-financial information relating to our power plants and complexes as of February 27, 2017. The generating capacity of certain of our power plants and complexes listed below has been updated from our 2015 disclosure to reflect changes in the resource temperature and other factors that impact resource capabilities:

Type	Region	Plant	Ownership(1)	Generating capacity (MW) (2)	Region 2016 Capacity Factor
Geothermal	California	Ormesa Complex	100%	40(3)
		Heber Complex	100%	92
		Mammoth Complex	100%	29
		North Brawley	100%	18
					78%
	West Nevada	Steamboat Complex	100%	73
		Brady Complex	100%	18
					87%
	East Nevada	Tuscarora	100%	18
		Jersey Valley	100%	10
		McGinness Hills	100%	86
		Don A. Campbell	63.3%	41
					97%
	Hawaii	Puna	63.3%	38
					78%
	International	Amatitlan	100%	20
		Zunil	97%	23
		Olkaria III Complex	100%	139(4)
		Bouillante	60%	15(5)
					96%
Total Geothermal				660	89%
REG		OREG 1	63.3%	22
		OREG 2	63.3%	22
		OREG 3	63.3%	5.5
		OREG 4	100%	3.5(6)
Total REG				53	83%
Total				713

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(1)

We indirectly own and operate all of our power plants, although financial institutions hold equity interests in three of our consolidated subsidiaries: (i) OPC, which owns the Desert Peak 2 power plant in our Brady complex and the Steamboat Hills, Galena 2 and Galena 3 power plants in our Steamboat complex; (ii) ORTP, which owns the Heber complex, the Ormesa complex, the Mammoth complex, the Steamboat 2 and 3 and Burdette (Galena 1) power plants in our Steamboat complex, and Brady power plant in our Brady complex; and (iii) Opal, which owns the McGinness Hills geothermal power plant complex, the Tuscarora and Jersey Valley power plants and the second phase of the Don A. Campbell power plant, all in Nevada; In the table above, we list these power plants as being 100% owned because all of the generating capacity is owned by either OPC, ORTP or Opal and we control the operation of the power plants. The nature of the equity interests held by the financial institutions is described below in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the headings “OPC Transaction”, “ORTP Transaction”, “and “Opal Transaction”.

In the table above, we list 100% of the generating capacity of the Bouillante power plant and the power plants in the ORPD portfolio because, we control their operation. We own a 60% equity interest in the Bouillante power plant and a 63.25% equity interest in ORPD, which owns the Puna, the first phase of the Don A. Campbell, the OREG 1, OREG 2 and OREG 3 power plants, as well as a partial indirect ownership interest in the second phase of the Don A. Campbell power plant.

(2)

References to generating capacity generally refer to the gross generating capacity less auxiliary power in the case of all of our existing power plants, except the Zunil power plant. We determine the generating capacity figures in these power plants by taking into account resource capabilities. In the case of the Zunil power plant, revenues are calculated based on a 24 MW capacity unrelated to the actual performance of the reservoir. This column represents our net ownership in such generating capacity.

In any given year, the actual power generation of a particular power plant may differ from that power plant’s generating capacity due to variations in ambient temperature, the availability of the resource, and operational issues affecting performance during that year.

⁽³⁾ The generating capacity of the Ormesa complex was reduced in 2016 mainly due to lower performance of the resource.

⁽⁴⁾ Plant 4 in the Olkaria III complex reached commercial operation on January 18, 2016 increasing the complex’s capacity by 29 MW to 139 MW.

⁽⁵⁾ In July 2016, we announced the acquisition of the Bouillante power plant in Guadeloupe. Ormat and CDC own 60% and 20% of the project through GB and Sageos owns 20% of the project.

⁽⁶⁾ The OREG 4 power plant is not operating at full capacity because of low run time of the compressor station that serves as the power plant’s heat source. This results in lower power generation.

All of the revenues that we derive from the sale of electricity are pursuant to long-term PPAs. Approximately 41.3% of our total revenues in the year ended December 31, 2016 were derived from the sale of electricity by our domestic power plants to power purchasers that currently have investment grade credit ratings. The purchasers of electricity from our foreign power plants are either state-owned or private entities.

New Power Plants

We are currently in various stages of construction of new power plants and expansion of existing power plants. Our expansion plan includes 110 MW in generating capacity from geothermal power plants in the U.S., Honduras, Kenya and Indonesia that are fully released for construction. In addition, we have several projects in the U.S. Guadeloupe Island and Kenya that are either under initial stages of construction or under different stages of development with an aggregate capacity of between 135 MW and 140 MW.

We have substantial land positions across 34 prospects in the U.S., Guatemala, Guadeloupe, New Zealand, Indonesia, Honduras and Ethiopia that we expect will support future geothermal development, on which we have started or plan to start exploration activity. These land positions are comprised of various leases, exploration concessions for geothermal resources and an option to enter into geothermal leases.

New activity

We recently signed an agreement to acquire substantially all of the business and assets of VEI, as mentioned above and further discussed under “Recent Developments”. We expect to complete the acquisition early in fiscal year 2017 and for VEI's business and assets to be owned by our newly established, wholly-owned subsidiary Viridity. Using proprietary software and solutions, Viridity will continue VEI’s business, serving primarily retail energy providers and large C&I customers. Viridity’s offerings will enable its clients to optimize and monetize their energy management, demand response and storage facilities potential by interacting on their behalf with regional transmission organizations and independent system operators.

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With its VPower^TM software platform, Viridity will manage curtailable customer loads of over 850 MW across 3,000 sites under contracts with leading U.S. retail energy providers and directly with large C&I customers, including management of a portfolio of non-utility storage assets located in the northeastern U.S. with over 80,000 operational market hours. Viridity will serve its distributed customers through a network operations center which is operated 24/7 based using Viridity’s VPowerMarkets^TM software platform, a SCADA platform. VPower^TM services will be provided to customers using a SaaS model where we will receive license fees and/or portion of the revenue and savings that are achieved for the customer.

In connection with this transaction, the Company will assume certain contractual duties and obligations that are regulated by the FERC and three RTOs. Specifically, Veridity will need to obtain and maintain (1) authorization from FERC to make wholesale sales of power, capacity, and ancillary services at market-based rates, and (2) membership status with eligibility to serve designated contractual functions in the RTOs of PJM, the NYISO, and the ERCOT.   We have submitted the required applications to FERC and the RTOs and have already received formal notice of membership in PJM.  In the future, we may need to obtain and maintain similar membership and eligibility status with other RTOs where the new business will operate.

Our Product Business (Product Segment)

We design, manufacture and sell products for electricity generation and provide the related services described below. We primarily manufacture products to fill customer orders, but in some situations, we may manufacture products as inventory for future internal and external projects.

Power Units for Geothermal Power Plants. We design, manufacture and sell power units for geothermal electricity generation, which we refer to as OECs. In geothermal power plants using OECs, geothermal fluid (either hot water (also called brine) or steam or both) is extracted from the underground reservoir and flows from the wellhead to a vaporizer that also heats a secondary working fluid, which is vaporized and used to drive the turbine. The secondary fluid is then condensed in a condenser, which may be cooled directly by air or by water from a cooling tower and sent back to the vaporizer. The cooled geothermal fluid is then reinjected back into the reservoir. Our customers include contractors and geothermal power plant developers, owners and operators.

Power Units for Recovered Energy-Based Power Generation. We design, manufacture and sell power units used to generate electricity from recovered energy, or so-called “waste heat”. This heat is generated as a residual by-product of gas turbine-driven compressor stations, solar thermal units and a variety of industrial processes, such as cement manufacturing, and is not otherwise used for any purpose. Our existing and target customers include interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators, and other companies engaged in other energy-intensive industrial processes.

EPC of Power Plants. We engineer, procure, and construct, as an EPC contractor, geothermal and recovered energy power plants on a turnkey basis, using power units we design and manufacture. Our customers are geothermal power plant owners as well as our target customers for the sale of our recovered energy-based power units as described above. Unlike many other companies that provide EPC services, we believe we have an advantage in that we are using our own manufactured equipment and thus have better quality and better control over the timing and delivery of required equipment and its related costs. As part of our strategy and collaboration agreement with Toshiba, we might have EPC contracts that are based on Toshiba power units. We also expect to develop additional knowledge in integrating Toshiba power units combined with our OECs in order to maximize the benefits to our customers.

Remote Power Units and Other Generators. We design, manufacture and sell fossil fuel powered turbo-generators with capacities ranging from 200 watts to 5,000 watts, which operate unattended in extreme hot or cold climate conditions. Our customers include contractors who install gas pipelines in remote areas and off-shore platforms operators and contractors. In addition, we design, manufacture, and sell generators, including heavy duty direct-current generators, for various other uses.

History

We were formed as a Delaware corporation in 1994 by Ormat Industries. Ormat Industries was one of the first companies to focus on the development of equipment for the production of clean, renewable and generally sustainable forms of energy. On February 12, 2015, we successfully completed the acquisition of Ormat Industries, eliminating its majority ownership and control of us.

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Industry Background

Geothermal Energy

Most of our power plants in operation produce electricity from geothermal energy. There are several different sources or methods of obtaining geothermal energy, which are described below.

Hydrothermal geothermal-electricity generation — Hydrothermal geothermal energy is derived from naturally occurring hydrothermal reservoirs that are formed when water comes sufficiently close to hot rock to heat the water to temperatures of 300 degrees Fahrenheit or more. The heated water then ascends toward the surface of the earth where, if geological conditions are suitable for its commercial extraction, it can be extracted by drilling geothermal wells. Geothermal production wells are normally located within several miles of the power plant, as it is not economically viable to transport geothermal fluids over longer distances due to heat and pressure loss. The geothermal reservoir is a renewable source of energy if: (i) natural ground water sources and reinjection of extracted geothermal fluids are adequate over the long-term to replenish the geothermal reservoir following the withdrawal of geothermal fluids and (ii) the well field is properly operated. Geothermal energy power plants typically have higher capital costs (primarily as a result of the costs attributable to well field development) but tend to have significantly lower variable operating costs (principally consisting of maintenance expenditures) than fossil fuel-fired power plants that require ongoing fuel expenses.

EGS — An EGS is a subsurface system that may be artificially created to extract heat from hot rock where the permeability and aquifers required for a hydrothermal system are insufficient or non-existent. A geothermal power plant that uses EGS techniques recovers the thermal energy from the subsurface rocks by creating or accessing a system of open fractures in the rock through which water can be injected, heated through contact with the hot rock, returned to the surface in production wells and transferred to a power unit.

Co-produced geothermal from oil and gas fields, geo-pressurized resources — Another source of geothermal energy is hot water produced as a by-product of oil and gas extraction. When oil and gas wells are deep, the extracted fluids are often at high temperatures and if the water volume associated with the extracted fluids is significant, the hot water can be used for power generation in equipment similar to a geothermal power plant.

Geothermal Power Plant Technologies

Geothermal power plants generally employ either binary systems or conventional flash design systems, as briefly described below. In our geothermal power plants, we also employ our proprietary technology of combined geothermal cycle systems.

Binary System

In a geothermal power plant using a binary system, geothermal fluid (either hot water (also called brine) or steam or both) is extracted from the underground reservoir and flows from the wellhead through a gathering system of insulated steel pipelines to a vaporizer that also heats a secondary working fluid. This is typically an organic fluid, such as pentane or butane, which is vaporized and is used to drive the turbine. The organic fluid is then condensed in a condenser, which may be cooled directly by air or by water from a cooling tower and sent back to the vaporizer through a pump. The cooled geothermal fluid is then reinjected back into the reservoir. Ormat’s air-cooled binary geothermal power plant is depicted in the diagram below.

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Flash Design System

In a geothermal power plant using flash design, geothermal fluid is extracted from the underground reservoir and flows from the wellhead through a gathering system of insulated steel pipelines to flash tanks and/or separators. There, the steam is separated from the brine and is sent to a demister, where any remaining water droplets are removed. This produces a stream of dry saturated steam, which drives a steam turbine generator to produce electricity. In some cases, the brine at the outlet of the separator is flashed a second time (dual flash), providing additional steam at lower pressure used in the low pressure section of the steam turbine to produce additional electricity. Steam exhausted from the steam turbine is condensed in a surface or direct contact condenser cooled by cold water from a cooling tower. The non-condensable gases (such as carbon dioxide) are removed by means of a vacuum system in order to maintain the performance of the steam condenser. The resulting condensate is used to provide make-up water for the cooling tower. The hot brine remaining after separation of steam is injected (either directly or after passing through a binary plant to produce additional power from the residual heat remaining in the brine) back into the geothermal resource through a series of injection wells. The flash technology is depicted in the diagram below.

In some instances, the wells directly produce dry steam and the steam is fed directly to the steam turbine with the rest of the system similar to the flash power plant described above.

Our Proprietary Technology

Our proprietary technology may be used either in power plants operating according to the Organic Rankine Cycle alone or in combination with various other commonly used thermodynamic technologies that convert heat to mechanical power, such as gas and steam turbines. It can be used with a variety of thermal energy sources, such as geothermal, recovered energy, biomass, solar energy and fossil fuels. Specifically, our technology involves original designs of turbines, pumps, and heat exchangers, as well as formulation of organic motive fluids (all of which are non-ozone-depleting substances). Using advanced computational fluid dynamics techniques and other computer aided design software as well as our test facilities, we continuously seek to improve power plant components, reduce operations and maintenance costs, and increase the range of our equipment and applications. We are always examining ways to increase the output of our plants by utilizing evaporative cooling, cold reinjection, configuration optimization, and topping turbines. In the geothermal as well as the recovered energy (waste heat) areas, we are examining two-level, three-level energy systems and other thermodynamic cycle alternations along with new motive fluids.

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We also developed, patented and constructed GCCU power plants in which the steam first produces power in a backpressure steam turbine and is subsequently condensed in a vaporizer of a binary plant, which produces additional power. Ormat Geothermal Combined Cycle technology is depicted in the diagram below.

In the conversion of geothermal energy into electricity, our technology has a number of advantages over conventional geothermal steam turbine plants. A conventional geothermal steam turbine plant consumes significant quantities of water, causing depletion of the aquifer and requiring cooling water treatment with chemicals and thus a need for the disposal of such chemicals. A conventional geothermal steam turbine plant also creates a significant visual impact in the form of an emitted plume from the cooling towers, especially during cold weather. By contrast, our binary and combined cycle geothermal power plants have a low profile with minimum visual impact and do not emit a plume when they use air-cooled condensers. Our binary and combined cycle geothermal power plants reinject all of the geothermal fluids utilized in the respective processes into the geothermal reservoir. Consequently, such processes generally have no emissions.

Other advantages of our technology include simplicity of operation, easy maintenance and higher yearly availability. For instance, the OEC employs a low speed and high efficiency organic vapor turbine directly coupled to the generator, eliminating the need for reduction gear. In addition, with our binary design, there is no contact between the turbine blade and geothermal fluids, which can often be very corrosive and erosive. Instead, the geothermal fluids pass through a heat exchanger, which is less susceptible to erosion and can adapt much better to corrosive fluids. In addition, with the organic vapor condensed above atmospheric pressure, no vacuum system is required.

We use the same elements of our technology in our recovered energy products. The heat source may be exhaust gases from a Brayton cycle gas turbine, low-pressure steam, or medium temperature liquid found in the process industries such as oil refining and cement manufacturing. In most cases, we attach an additional heat exchanger in which we circulate thermal oil or water to transfer the heat into the OEC’s own vaporizer in order to provide greater operational flexibility and control. Once this stage of each recovery is completed, the rest of the operation is identical to that of the OECs used in our geothermal power plants and enjoys the same advantages of using the Organic Rankine Cycle. In addition, our technology allows for better load following than conventional steam turbines, requires no water treatment (since it is air cooled and organic fluid motivated), and does not require the continuous presence of a licensed steam boiler operator on site.

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Ormat’s REG technology is depicted in the diagram below.

Patents

We have 73 U.S. patents that are in force (and have approximately 16 U.S. patents pending). These patents and patent applications cover our products (mainly power units based on the Organic Rankine Cycle) and systems (mainly geothermal power plants and industrial waste heat recovery plants for electricity production). The products-related patents cover components that include turbines, heat exchangers, seals and controls as well as control of operation of geothermal production well pumps. The system-related patents cover not only particular components but also the overall energy conversion system from the “fuel supply” (e.g., geothermal fluid, waste heat, biomass or solar) to electricity production.

The system-related patents cover subjects such as waste heat recovery related to gas pipeline compressors and industrial waste heat, solar power systems, disposal of non-condensable gases present in geothermal fluids, power plants for very high pressure geothermal resources, two-phase fluids as well as processes related to EGS. A number of our patents cover combined cycle geothermal power plants, in which the steam first produces power in a backpressure steam turbine and is subsequently condensed in a vaporizer of a binary plant, which produces additional power. The remaining terms of our patents range from one year to 18 years. The loss of any single patent would not have a material effect on our business or results of operations.

Research and Development

We are conducting research and development activities intended to improve plant performance, reduce costs, and increase the breadth of our product offerings. The primary focus of our research and development efforts is targeting power plant conceptual thermodynamic cycle and major equipment including continued performance, cost and land usage improvements to our condensing equipment, and development of new higher efficiency and higher power output turbines.

Additionally, we are continuing to evaluate investment opportunities in new companies with technology and/or product offerings for renewable energy and energy storage solutions.

Market Opportunity

Geothermal Market Opportunities

United States

Interest in geothermal energy in the U.S. remains strong for numerous reasons, including legislative support of RPS, coal and nuclear base load energy retirement and increasing awareness of the positive value of geothermal characteristics as compared to intermittent renewable technology.

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Today, electricity generation from geothermal resources is concentrated mainly in California, Nevada, Hawaii, Idaho and Utah, and we believe there are opportunities for development in other states such as Arizona, New Mexico, Washington and Oregon due to the potential of their geothermal resources.

In a report issued in March 2016, the GEA indicated that the U.S. geothermal industry had about 3,700 MW of installed nameplate capacity and over 80 active projects with a cumulative capacity of over 1,250 MW of geothermal projects under various phases of consideration or development in 10 U.S. states.

Geothermal energy provides numerous benefits to the U.S. grid and economy, according to another GEA report issued in January 2017. Geothermal development and operation brings economic benefits in the form of taxes and long term high-paying jobs, and it has one of the lowest LCOE of all power sources in the U.S. Additionally, improvements in geothermal production make it possible to provide ancillary and on-demand services. This helps load serving entities avoid additional costs from purchasing and then balancing intermittent resources with storage or new transmission.

In recent years, according to the GEA, the U.S. geothermal market experienced modest growth and a decline in the development inventory of geothermal projects. This decline can be attributed to projects reaching completion, industry consolidation, and developers discontinuing projects they elected to put on hold for the time being. Management’s view is that this decline is also caused by an unbalanced mechanisms for valuing baseload power and integration costs in California and Nevada where a significant amount potential of U.S. geothermal resources are located. Most integration costs are not accounted for in bids for renewable resources. This creates an advantage for the intermittent resources as they receive a free pass for costs they create as compare to the positive attributes and ancillary benefits of baseload resources. Not all buyers accurately account for the negative impact of intermittent renewables in areas such as curtailment due to over-generation, strains on the transmission grid, the need for backup capacity, the diminishing value of energy during solar PV hours, the inefficient use of transmission capacity etc. Buyers also typically do not properly value the flexibility benefits of geothermal resource.

The successful implementation of the various geothermal projects identified by the GEA depends on the respective project sponsor’s ability to fully identify the resource, conduct exploration, and carry out development and construction. Accordingly, the GEA estimates may not be realized, and differences between the actual number of projects completed and those initially estimated to be completed may be material. We refer to the GEA assessment as a possible reference point, but we do not necessarily concur with its estimate.

State level legislation

One of the factors supporting growth in the renewable energy industry is global concern about climate change. In response to increasing demand for “green” energy, many states have adopted legislation requiring, and providing incentives for, electric utilities to sell electricity generated from renewable energy sources. In the U.S., 37 states plus the District of Colombia and four territories have enacted an RPS, renewable portfolio goals, or similar laws requiring or encouraging utilities in such states to generate or buy a certain percentage of their electricity from renewable energy or recovered heat sources.

According to the Database of State Incentives for Renewables and Efficiency (DSIRE), 30 states and two territories (including California, Nevada, and Hawaii, where we have been the most active in our geothermal energy development and in which all of our operating U.S. geothermal power plants are located) and the District of Columbia define geothermal resources as “renewable”. In addition, according to the EPA, 25 states have enacted RPS, Clean Energy Standards, Energy Efficiency Resource Standards or Alternative Portfolio Standards program guidelines that include some form of combined heat and power and/or waste heat recovery.

We see the impact of RPS legislation as the most significant driver for us to expand existing power plants and to build new projects.

California

The California RPS was established in 2002 under Senate Bill (SB) 1078, accelerated in 2006 under SB 107 and further expanded in 2011 under SB x1-2. The RPS program requires investor-owned utilities (IOUs), electric service providers, community choice aggregators and publicly owned utilities to increase their share of procurement from eligible renewable energy resources as a percentage of their total procurement. The RPS requirements for utilities to procure of 33 percent of their energy from renewable resources by 2020 was revised in October 2015, when Governor Jerry Brown signed into law SB 350 requiring that 50 percent of total retail electricity sales be from renewable resources by 2030, with interim targets of 40 percent by 2024, and 45 percent by 2027.

According to the CPUC Renewable Portfolio Standard Quarterly Report for the fourth quarter of 2016, California’s three largest IOUs collectively generated 27.6% of their 2015 retail electricity sales from renewable resources. These utilities have interim targets each year, with a requirement to attain RPS of 25% by 2016. Publicly-owned utilities in California are also required to procure 50% of retail electricity sales from eligible renewable energy resources by 2030, opening up an additional market of potential off-takers for us. This expanded target could benefit geothermal energy, which has the advantage of generating flexible base load power, and helping California diversify its mix of renewable resources.

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In 2006, California passed a state climate change law, Assembly Bill (AB) 32, to reduce GHG emissions to 1990 levels by the end of 2020, and in December 2010, the CARB approved cap-and-trade regulations to reduce California’s GHG emissions below the levels set by AB 32. The regulations set a limit on emissions from sources responsible for emitting 80% of California’s GHGs. On November 2016, the CARB released the results of its ninth joint auction for California and Québec allowances reporting that the vintage 2016 auction clearing price was $12.73 per allowance and the future vintage auction clearing price was $12.73 per allowance. All of the available 2016 and vintage allowances offered were sold.

In 2014, AB 2363 became effective, requiring the CPUC to adopt by December 31, 2015 a methodology for determining the costs of integrating eligible renewable energy resources. The process has experienced some delays, and currently the CPUC is incorporating the development of this methodology into its Integrated Resource Planning process. We expect that the CPUC will issue new guidelines in this regard in 2017.

Nevada

Nevada’s RPS was first adopted by the Nevada Legislature in 1997. Nevada’s RPS targets were revised and expanded and currently require NV Energy to supply at least 25% of the total electricity it sells from eligible renewable energy resources by 2025. For 2015, Nevada’s RPS required that at least 20% of electricity sold to Nevada retail customers be from renewable energy resources and credits, and at least 5% of that amount be from solar resources. According to NV Energy’s Annual RPS Compliance Report, in 2015, Nevada Power exceeded both the 2015 RPS standard and the 2015 solar RPS requirement, achieving 21.2% and 31.0%, respectively. Sierra exceeded both the 2015 RPS standard and the 2015 solar RPS requirement, with 31.3% and 22.8% respectively.

In June 2013, the Nevada state legislature passed three bills that were signed into law and expected to support renewable energy development. SB No. 123 requires an electric utility to submit a plan for the retirement or elimination of not less than 800 MW of coal-fired electric generating capacity on or before December 31, 2019 and the construction or acquisition of, or contracting for, 350 MW of electric generating capacity from renewable energy facilities. SB No. 252 revises provisions relating to the renewable portfolio standard by removing energy efficiency, solar multipliers, and station usage from generating portfolio energy credits (PECs). Finally, AB No. 239 Revised Statutes 701A.340 defines geothermal energy as renewable energy for purposes of tax abatements and makes geothermal projects eligible to apply for partial sales and property tax abatements, with property tax abatements for 20 years and local sales and use tax abatements for three years.

Hawaii

Hawaii established a renewable portfolio goal in 2001. Since 2001, the RPS targets were revised and expanded.  On June 2015, Hawaii became the only state with a legislative goal of 100% renewable energy by 2045 with the signing of HB 623. The new policy includes interim requirements of 15% by the end of 2015, 30% by the end of 2020, 40% by 2030, and 70% by 2040, ultimately reaching 100% renewable electricity by 2045.

Hawaiian Electric Company and its subsidiaries exceeded the 2015 RPS requirement, achieving a consolidated RPS of 23.2% of retail electricity sales from eligible renewable energy resources.

Multi-State Climate Initiatives

Other state-wide and regional initiatives are also being developed to reduce GHG emissions and to develop trading systems for renewable energy credits. For example, nine Northeast and Mid-Atlantic States are part of the RGGI, a regional cap-and-trade system to limit carbon dioxide. The RGGI was the first, market-based carbon dioxide emissions reduction program in the U.S. The RGGI states implemented a new 2014 RGGI cap of 91 million short tons and plan to reduce carbon emissions from power plants at a rate of 2.5% per year between 2015 and 2020. States sell nearly all emission allowances through auctions and invest proceeds in energy efficiency, renewable energy and other consumer benefit programs. These programs are spurring innovation in the clean energy economy and creating green jobs in the RGGI states.

In addition to RGGI, other states have also established the Midwestern Regional Greenhouse Gas Reduction Accord and the Western Climate Initiative.

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Although individual and regional programs will take some time to develop, their requirements, particularly the creation of any market-based trading mechanism to achieve compliance with emissions caps, should be advantageous to in-state and in-region (and, in some cases, such as RGGI and the State of California, inter-regional) energy generating sources that have low carbon emissions such as geothermal energy. The role or importance of such programs remains unclear following the 2016 U.S. presidential election.

In December 2015, the White House announced that 154 companies from across the American economy signed the American Business Act on Climate Pledge to demonstrate their support for action on climate change. By signing the American Business Act on Climate pledge, these companies are demonstrating an ongoing commitment to climate action. As part of this initiative, each company is announcing significant pledges to reduce their emissions, increase low-carbon investments, deploy more clean energy, and take other actions to build more sustainable businesses and tackle climate change.

Although it is currently difficult to quantify the direct economic benefit of these efforts to reduce GHG emissions, we believe they will prove advantageous to us.

Federal level legislation

On August 3, 2015, President Obama and the EPA announced the Clean Power Plan that sets standards for power plants and customized goals for states to cut carbon pollution. The goal of the proposed plan includes cutting carbon emissions from the power sector by 32% below 2005 levels nationwide by 2030. In February 2016, the Supreme Court of the U.S. granted a temporary stay halting implementation of the Clean Power Plan pending resolution of legal challenges to the proposed plan. The U.S. Court of Appeals for the District of Columbia Circuit heard oral arguments in the cases challenging the Clean Power Plan on September 27, 2016. The court has not issued its decision, and it remains unclear exactly what action the Trump Administration will take, although the Trump Administration has expressed its desire to eliminate the Clean Power Plan and general skepticism of climate change.

The federal government also encourages production of electricity from geothermal resources or solar energy through certain tax subsidies. For a new geothermal power plant in the U.S. that started construction by December 31, 2016, we are permitted to claim a tax credit based on the power produced from a geothermal power plant. These production-based credits, which in 2016 were 2.3 cents per kWh, are adjusted annually for inflation and may be claimed for ten years on the electricity produced by the project and sold to third parties after the project is placed in service. In lieu of the production tax credits, we are permitted to claim a tax credit against our U.S. federal income taxes equal to 30% of certain eligible costs when the project is placed in service, so long as the project was under construction by the end of 2016. If the project was not under construction in time, then we are permitted to claim a 10% investment tax credit. The owner of the power plant may not claim both the investment tax credit and the production-based tax credit. New solar projects that are under construction by December 2019 will qualify for a 30% investment tax credit. The credit will fall to 26% for projects starting construction in 2020 and 22% for projects starting construction in 2021. Projects that are under construction before these deadlines must be placed in service by December, 31 2023 to qualify for the higher investment tax credit. Projects placed in service after December, 31, 2023 will only qualify for a 10% investment tax credit. Under current tax rules, any unused tax credit has a one-year carry back and a twenty-year carry forward.

We are also permitted to depreciate, or write off, most of the cost of the plant. In cases where we claim the one-time 30% (or 10%) tax credit, our tax basis in the plant that we can recover through depreciation is reduced by one-half of the tax credit. In cases where we claim the production tax credit, there is no reduction in the tax basis for depreciation. Projects that are placed in service in 2016 and 2017 are eligible for “bonus” depreciation and we will be permitted to write off 50% of the cost of that equipment in the year the power plant is placed in service. Projects placed in service in 2018 would qualify for a 40% bonus and Projects placed in service in 2019 would qualify for a 30% bonus. After applying any depreciation bonus that is available, we can write off the remainder of our tax basis in the plant, if any, over five years on an accelerated basis, meaning that more of the cost may be deducted in the first few years than during the remainder of the depreciation period.

Collectively, these benefits (to the extent they are fully utilized) have a present value equivalent to approximately 30% to 40% of the capital cost of a new power plant.

Global

We believe the global markets continue to present growth and expansion opportunities in both established and emerging markets.

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According to the GEA’s Geothermal Power: International Market Update, the global geothermal market was developing about 2.5 GW of planned capacity spread across 23 countries. Additionally, the GEA estimates that, based on current data, the global geothermal industry is expected to grow from 13.8 GW today to reach 23 GW by 2021.

The assessment conducted by the GEA is only an estimate that is based on projects and resource reporting by the geothermal industry. A developer’s ability to fully develop a geothermal resource is dependent upon its capabilities to identify the resource and conduct exploration, development and construction; therefore, this estimate may not be accurate. We refer to it only as a possible reference point, but we do not necessarily concur with this estimate.

Operations outside of the U.S. may be subject to and/or benefit from increasing efforts by governments and businesses around the world to fight climate change and move towards a low carbon, resilient and sustainable future. According to a 2017 report from the International Renewable Energy Agency entitled Rethinking Energy, to date, more than 170 countries have established renewable energy targets, and nearly 150 have enacted policies to catalyze investments in renewable energy technologies.

In December 2015, 197 countries signed an historic agreement at the COP21 UN Climate Change Conference held in Paris. For the first time, all countries committed to setting nationally determined climate targets and reporting on their progress. The agreement’s aim is to keep global temperature rise this century well below 2 degrees Celsius and to drive efforts to limit the temperature increase even further to 1.5 degrees Celsius above pre-industrial levels. According to the United Nations Framework Convention on Climate Change (UNFCCC),the submission of national targets in five-year cycles signals to investors and technology innovators that the world will demand clean power plants, energy efficient factories and buildings, and low-carbon transportation in the decades to come.

The Paris Agreement entered into force on November 4, 2016, thirty days after the date on which at least 55 parties to the Convention accounting in total for at least an estimated 55% of the total global greenhouse gas emissions deposited their instruments of ratification, acceptance, approval or accession with the Depositary. 127 Parties have ratified of 197 Parties to the Convention.

In support of the Paris agreement, the EIB has committed to provide $100 billion of new financing for climate action projects over the five years. The support of multilateral institutions such as EIB is expected to be an important factor in assisting countries in reaching their targets under the Paris Climate Change Agreement.

In November 2015, a group of 20 countries, including the US, UK, France, China and India, pledged to double their budget for renewable energy technology over the next five years as part of a separate initiative called Mission Innovation. 

Also in November 2015, the Breakthrough Energy Coalition was launched by a group of 28 private investors with the objective of bringing companies with the potential to deliver affordable, reliable and carbon free power from the research lab to the market.

We believe that these developments and governmental plans will create opportunities for us to acquire and develop geothermal power generation facilities internationally, as well as create additional opportunities for our Product segment.

Outside of the U.S., the majority of power generating capacity has historically been owned and controlled by governments. Since the early 1990s, however, many foreign governments have privatized their power generation industries through sales to third parties encouraging new capacity development and/or refurbishment of existing assets by independent power developers. These foreign governments have taken a variety of approaches to encourage the development of competitive power markets, including awarding long-term contracts for energy and capacity to independent power generators and creating competitive wholesale markets for selling and trading energy, capacity, and related products. Some foreign regions and countries have also adopted active government programs designed to encourage clean renewable energy power generation such as the following countries in which we operate and/or are conducting business development activities:

Europe

Turkey has the richest known geothermal resources in Europe with the theoretical potential for 31,000 MW of geothermal capacity and with a proven geothermal capacity of 4.5 GW, according to the Turkish Mineral Technical Exploration Agency.

Since 2004, we have established strong relationships in the Turkish market and provided our full range of solutions including our state-of-the-art binary systems to 28 geothermal power plants with a total capacity of nearly 515 MW, of which 6 power plants are currently under construction.

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In Turkey, the National Renewable Energy Action Plan' proposes to increase the country's renewable energy generation capacity to 61 GW by 2023, including 1.5 GW of geothermal. The plan is supported by the European Bank for Reconstruction and Development. The plan aims to increase Turkish energy security by diversifying its energy supply, make greater use of domestic resources, protect the environment by relying on clean, renewable and low carbon technologies and foster energy market efficiency through private sector investment and integration.

The plan also seeks to attract private investments in research and development and in geothermal exploitation for electricity production and to provide financial support to innovation and technology research in the field of renewable energies. Special emphasis and attention has been placed on using locally manufactured equipment in renewable energy based generating facilities, with a target set for 45% of equipment used in such facilities by the end of 2019 to be manufactured locally.

To achieve its objective of having 30% of its power generated from renewable sources by 2023, Turkey has changed the renewable energy law first enacted in 2007. The law sets the FITs for geothermal energy at $105 per MWh for ten years from COD and provides a further incentive of $13 per MWh for local manufacturing parts for five years from COD. This last update of the law is valid until 2020. Renewable energy producers will also benefit from an 85% discount on transmission costs for 10 years and various priority rights over land usage. In order to benefit from the incentives under the renewable energy law, a renewable energy generation facility must hold a renewable energy resource certificate (the RER Certificate), which is issued by Turkey’s Energy Market Regulatory Authority. The RER Certificate will be valid for the term of the generation license of the relevant generation company. In addition, and to avoid rights and licenses manipulation, a pre-feasibility license must be issued and paid for upon the request to hold a concession. These pre-licenses must be turned into full licenses for developed fields within three years of issuance, or they become void and the license rights may be re-assigned without fee reimbursement.

Latin America

Several Latin American countries have renewable energy programs. In November 2013, the national government of Guatemala, where our Zunil and Amatitlan power plants are located, approved a law creating incentives for power generation from renewable energy sources. These incentives include, among other things, providing economic and fiscal incentives such as exemptions from taxes on the importation of relevant equipment and various tax exemptions for companies implementing renewable energy projects. Additionally, the Energy Policy 2013-2027 identifies great untapped potential for renewable energy production in Guatemala, including 1,000 MW for geothermal. One of the main objectives of the Energy Policy is to secure a supply of electricity at competitive prices by diversifying the energy mix with an 80% renewable energy share target for 2027.

In Honduras, where we are building the first geothermal power plant under a BOT agreement, the national government approved the Incentives Act (Decree No.70-2007) providing incentives in the form of tax exemptions for equipment, materials and services related to power generation development based on renewable resources. At the same time, ENEE, the national integrated utility, will buy energy from such projects and offer to pay rates that are above the marginal cost approved by the CNE. Honduras also set a target to reach at least 80% renewable energy production by 2034.

In Chile, the Chilean Renewable Energy Act of 2008 required 5% of electricity sold, to come from renewable sources, increasing gradually to 10% by 2024. On October 14, 2013, the President of Chile signed into law a bill which mandates that utilities source 20% of their electricity from “non-conventional” renewable energy, including solar PV and concentrating solar power, by 2025.

Mexico is the world’s fourth largest producer of geothermal energy. Recent studies suggest an over 9,000 MW geothermal potential, of which only 12% is already developed. In December 2013, the Mexican Congress passed a constitutional reform in an attempt to increase the participation of private investors in the generation and commercialization of electric energy. This reform affects the electricity market by opening the generation and commercialization of electricity to private companies, transforming the Federal Electricity Commission to a for-profit public company, and redefining the functions and attributions of the Ministry of Energy. The secondary legislation that establishes the attributions of the public entities, procurement regulations, and normative framework for the productive State companies was finalized in 2014.

In July 2015, Mexico launched round zero and assigned the projects to be developed by Mexico's state-owned utility CFE, with the remainder to be put out to tender to the private sector. Thirteen geothermal areas and five concessions were given by the Mexican Secretariat of Energy to the CFE. The government expects to award private companies with concessions for 30 years and permits for up to 150 km² for three years in the case of exploration. Ormat is in various discussions with local companies to identify attractive geothermal resources and projects.

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Many island nations in general and specifically the Caribbean nations, depend almost entirely on petroleum to meet their electricity demands. With an average electricity price of US$35 per kWh in 2014, the lack of diversified power generation leaves Caribbean nations vulnerable to commodity market volatility, while the lack of new development leaves them reliant on what are believed to be outdated and often unreliable power plants. The larger issue hindering large-scale renewable energy deployments, however, is scale. Caribbean nations have quite significant renewable energy potential yet most have small demand.  The majority of the Caribbean grids are relatively old, with the average diesel generators more than 20 years old. Furthermore, the power supply is relatively inefficient with high system losses.  Due to their sizes, each of the Caribbean countries is generally dominated by one local utility and simple market structures where electricity is regulated directly by local governments. Other than in Guadeloupe, where the geothermal power plant that we recently acquired has been operating since 1985, there are no other operating geothermal projects in the Caribbean region. Recently, some deep well drilling exploration was performed on a few islands, but the results of this exploration are still pending. Although few, we believe there are opportunities for us in the Caribbean islands of St. Kitts, Nevis, St. Lucia, Dominica, and Montserrat.

Oceania

In New Zealand, where we have been actively providing geothermal power plant solutions since 1988, the New Zealand government’s policies to fight climate change include an unconditional GHG emissions reduction target of between 10% and 20% below 1990 levels by 2020 and a target to increase renewable electricity generation to 90% of New Zealand’s total electricity generation by 2025.

South East Asia

In Indonesia, where we participate in the Sarulla project that is expected to start commercial operation of the first unit in March 2017, and where two other units are currently under construction, the government intends to increase the role of renewable energy sources and aims to have them meet 23% of domestic energy demand by 2025. The government has also implemented new policies and regulations intended to accelerate the development of renewable energy and geothermal projects in particular. In June 2014, the MEMR issued a new geothermal tariff policy. The MEMR reverted to a location-based tariff regime while adding a time dimension. The tariffs range from $0.118 to $0.296 per kWh between 2015 and 2025, depending on location. The tariffs provide a ceiling price for the power purchase agreements between project developers and PLN, the national utility and off taker. The tariffs were set to include the effect of inflation on projects that are expected to commence commercial operation in the distant future.

In addition, the 2014 National Energy Policy calls for the increased use of geothermal energy to represent at least 5% of the national energy mix by 2025.

In order to further accelerate geothermal development in the country a new FIT regime is expected to become effective during early 2017. The FIT is planned to range from $0.12 to $0.24 per kWh depending on size and location. Additionally, in January 2016, the government of Indonesia announced it will offer 21 geothermal blocks to investors over the next two years. Ormat plans to participate in select appropriate bids.

In the IPP sector, certain regulations for geothermal projects have been implemented, providing incentives such as investment tax credits, accelerated depreciation, and pricing guidelines to allow for preferential power prices for generators.

On January 2016, the President of Indonesia issued new presidential regulations (PR No. 4 2016) to accelerate the Indonesian 35 GW Power Generation Program. The regulations introduce a new government guarantee for development of power projects, which would cover both projects developed by the state-owned utility company, PLN, and those projects developed by PLN in cooperation with IPPs or their subsidiaries. Additionally, a shorter period to obtain necessary permits for development was introduced as well as clarifications that geothermal projects can be developed in high-conservation forest areas (e.g. national parks).

The Government of Indonesia is planning to revise negative investment regulation. According to Presidential Decree No. 39/2014, the development of geothermal power plants with a capacity of less than 10 MW is closed to foreign ownership. Currently, foreign investors may own up to 95 percent of plants with generating capacities greater than 10 MW. The revised regulations, currently under government review, will allow foreign entities to wholly own geothermal power plants with generating capacities greater than 10 MW and to own 67% of smaller sized geothermal power plants

The Government of Indonesia announced its intention to reduce the country’s carbon dioxide emissions by 26% by 2020 at the 2009 United Nations Climate Change Conference in Copenhagen and during 2015 in Paris.

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East Africa

In East Africa the geothermal potential along the Rift Valley is estimated at several thousand MW. The different countries along the Rift Valley are at different stages of development of their respective geothermal potentials.

In Kenya, there are already several geothermal power plants, including the only geothermal IPP in Africa, our Olkaria III complex. The Government of Kenya has identified the country's untapped geothermal potential as the most suitable indigenous source of electricity and it aspires to reach 5,000 MW of geothermal power by 2030. To attain such number, GDC was formed to fast track the development of geothermal resources in Kenya. Ormat has as a 51% interest in a consortium that signed a PPA for a 35 MW geothermal power plant in the Menengai area.

The Government of Kenya is aiming to reach 22.7GW of power generating capacity by 2033, under the Least-Cost Power Development Plan 2013-33 with a target of 42% of such capacity generated from renewable energy sources (including large hydro but excluding solar).

In December 2012, FITs for various technologies were reviewed and the process of negotiating PPAs streamlined. Projects under this mechanism have priority grid access at the cost of the developer. Geothermal projects from 35 MW to 70 MW have a USD $0.088 per kWh (up to 500MW) FIT.

In 2015, the Departmental Committee of Finance, Planning, and Trade amended the Income Tax Act in view of the 2015 Finance Bill. The amendments include maintaining the enhanced investment deduction of 150% under section 17B and extending the period of deduction of tax losses to over 10 years.

The governments of Djibouti, Ethiopia, Eritrea, Tanzania, Uganda, Rwanda and Zambia are exploring ways to develop geothermal in their countries, mostly through the help of international development organizations such as the World Bank.

In January 2014, energy ministers and delegates from 19 countries committed to the creation of the Africa Clean Energy Corridor Initiative (Corridor), at a meeting in Abu Dhabi convened by the International Renewable Energy Agency. The Corridor will boost the deployment of renewable energy and aim to help meet Africa’s rising energy demand with clean, indigenous, cost-effective power from sources including hydro, geothermal, biomass, wind and solar.

East Africa and South East Asia may benefit from two initiatives announced by President Obama. In June 2013, the Power Africa initiative was announced, which contemplated that the U.S. would invest up to $7.0 billion in sub-Saharan Africa over the ensuing five years with the aim of doubling access to power. The program will partner the U.S. government with the governments of six sub-Saharan countries, among them Kenya, Ethiopia and Tanzania, that have the potential for geothermal energy development. In 2012, President Obama proposed the U.S. Asia Pacific Comprehensive Energy Partnership that encourages U.S. companies to develop renewable energy in South East Asian countries, including Indonesia. The U.S. will provide up to $6.0 billion to support the Partnership. However, with the recent election of president Trump, the progress of these initiatives is uncertain

Other opportunities

Recovered Energy Generation

In addition to our geothermal power generation activities, we are pursuing recovered energy-based power generation opportunities in North America and the rest of the world. We believe recovered energy-based power generation will ultimately benefit from the efforts to reduce greenhouse gas emissions. For example, in the U.S., FERC has expressed its position that one of the goals of new natural gas pipeline design should be to facilitate the efficient, low-cost transportation of fuel through the use of waste heat (recovered energy) from combustion turbines or reciprocating engines that drive station compressors to generate electricity for use at compressor stations or for commercial sale. FERC has, as a matter of policy, requested natural gas pipeline operators filing for a certificate of approval for new pipeline construction or expansion projects to examine “opportunities to enhance efficiencies for any energy consumption processes in the development and operation” of the new pipeline. We have built over 21 power plants which generate electricity from “waste heat” from gas turbine-driven compressor stations along interstate natural gas pipelines, from midstream gas processing facilities, and from processing industries in general.

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Several states, and to a certain extent, the federal government, have recognized the environmental benefits of recovered energy-based power generation. For example, 18 states currently allow electric utilities to include recovered energy-based power generation in calculating such utilities' compliance with their mandatory or voluntary RPS and/or Energy Efficient Resources Standards. In addition, California modified the Self Generation Incentive Program, which allows recovered energy-based generation to qualify for a per watt incentive. 

In 2012, the Governor of Utah signed into law SB 12 that enables the sale of electricity generated from in-state renewable resources directly to large energy users. This direct purchase and sale, could create a market opportunity for our REG technology in Utah. The local utility has developed a tariff and contracts to provide rates and methodologies for companies that want to buy power directly from renewable generation facilities.

Also in 2012, SB 315 was enacted by the State of Ohio. SB 315 made waste energy recovery eligible as a renewable resource for purposes of meeting the state’s Renewable Portfolio Standard, as well as an efficiency measure under the state’s Energy Efficiency Resource Standard.

In addition, in Colorado the state PUC ruled that Xcel Energy, the largest utility in Colorado, will begin offering a $500 per kW incentive for recycled energy projects.The incentive will be paid out over 10 years to developers and manufacturers who convert waste heat from stacks and process it into electricity. Xcel Energy has developed a tariff to provide rates and a methodology for recycled energy projects that wish to take advantage of this incentive.

At the Federal level, under the Clean Power Plan, waste-heat-to-power (recovered energy) is an eligible technology that can be implemented by states as a means to comply with their Clean Power Plan emissions reduction targets. The inclusion of waste-heat-to-power as an eligible technology under the Clean Power Plan could potentially create demand for REG in states that have good waste-heat resources, but that so far had no policies in place, like an RPS, to create demand for renewables. However, there is now great uncertainty at the Federal level whether the current administration will keep the Clean Power Plan and its emissions reduction targets and strategies in place. The U.S. Court of Appeals for the District of Columbia Circuit heard oral arguments in the cases challenging the Clean Power Plan on September 27, 2016. The court has not issued its decision, and it remains unclear exactly what action the Trump Administration will take, although the Trump Administration has expressed its desire to eliminate the Clean Power Plan and general skepticism of climate change.

Recovery of waste heat is also considered “environmentally friendly” in the western Canadian provinces. On November 22, 2015, the Government of Alberta released the Clean Leadership Plan that includes (a) phasing out of coal-fired electricity generation by 2030; (b) a commitment to generate 30 percent of Alberta’s electricity from renewable sources by 2030; (c) new financing for energy efficiency; and (d) an economy-wide price on carbon pollution. The plan also includes mandating Alberta to reduce methane emissions from oil and gas operations by 45% by 2025.  This comprehensive set of climate policies, once fully implemented, will encourage the development of renewable energy technologies, including waste heat recovery, in Alberta. We believe that Europe and other markets worldwide may offer similar opportunities in recovered energy-based power generation.

In summary, the market for the recovery of waste heat converted into electricity exists either when the already available electricity is expensive or where the regulatory environment facilitates construction and marketing of power generated from recovered waste heat. However, such projects tend to be smaller than 9 MW and we expect the growth to be relatively slow and geographically scattered.

New activities under our strategic plan

The traditional grid is undergoing a major disruption. The continued decline in Solar PV prices is impacting renewable energy pricing and the growth in intermittent green energy is generating increasing strains on the grid, mainly in the U.S and Europe. The increasing amount of solar PV power being supplied to the grid can create situations where significant amount of power plant capacity must be available to ramp up and down to accommodate solar PV daily output cycles and variations due to atmospheric conditions. The output from Solar PV power plants can change significantly over short periods of time due to environmental conditions like cloud movement and fog burn off and that can cause instability on the electric grid. 

As a result, energy management and specifically electricity storage is becoming a key component of the future grid. In parallel, we see movement of C&I and communities toward direct purchases of electricity

and an increased focus on reliability of electricity supply.

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Energy Storage

Energy storage systems utilize low cost, surplus, available electricity that enables utilities to optimize the operation of the grid and generators to run closer to full capacity for longer periods of time and operate more efficiently and effectively. With the increasing use of wind and solar energy, the need for storage services such as balancing services, frequency regulation, rapid generation ramping and movement of energy from times of excess to times of high demand is becoming more important.

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The global energy storage market is still developing, with specific applications and geographies leading the overall market. After a record-breaking year in 2015, the energy battery storage industry is continuing to gain momentum globally. More than 1.6 GW of new deployments (approximately $2.0 billion) were announced worldwide in 2015. Various diversified battery storage technologies have been developed and deployed.

Much of the BESS activity is focused on energy storage for the grid and ancillary services. Behind the meter deployments are growing fast to enable customers to increase savings from demand charge reductions and create revenues through active market participation (demand response programs). Also, grids/utilities are undergoing significant changes such as grid aging, grid congestion, coal retirement, implementation of carbon reduction rules, increasing renewable energy and intermittent energy penetration. BESS delivers many benefits to grids and end users (behind the customer meter, as well as to micro-grids). Real-time balancing services can reactively increase stability and reliability on the grid to offset renewables inherent flexibility, to store energy now to be used later and promote business resiliency, power quality and physically distributed benefits for all segments of the grid or the end customer.

According to Navigant research, BESS continues to be one of the fastest growing segments of the broader energy industry, set to reach an overall installed power capacity of 143.7 GW and a cumulative global market size of $162.3 billion in the next 10-year period. This represents a CAGR of approximately 30% over the 10-year period in both in-front-of-the meter grid connected and behind-the-meter commercial and industrial deployments.

According to a Green Tech Media (GTM) report from December 2016 the U.S. behind-the-meter energy storage market today is small, with combined residential and non-residential deployments in 2015 accounting for only 15% of installed capacity in MW terms. By 2021, however, the behind-the-meter segment will account for half of the annual U.S. market, driven by a plethora of factors including improved system economics, net-energy metering reform, changes to utility rate structures, increasing viability of demand-charge management for non-residential customers, and increased interest in reliability and resiliency. GTM is expecting a total installations of more than 4 GW until 2021 in the U.S. These trends in the U.S. market are expected to be seen in other leading global markets in Europe, Asia and the Far East.

Following the closing of Viridity’s acquisition we will own substantially all of VEI’s business and assets and we plan to use the VEI platform to expand our market presence in the energy storage market and further develop VEI’s demand response VPower™ software platform and energy storage services. We expect that together with our global presence, experience in technology integration, and flexible business models, and our reputation and experience in the geothermal and recovered energy sectors we can expand into this growing sector.

C&I

The C&I sector is shifting from centralized electricity generation systems to distributed resources supported by emerging models of direct PPAs with renewable power plants, on-site deployments, and customized solutions to energy management. Participants in the C&I sector are motivated to purchase renewable energy to reduce costs and diversify their energy supply, to lock in long-term energy price stability and carbon footprint reductions, to achieve renewable energy targets and to demonstrate leadership, innovation, and competitive first mover advantages. Ormat sees C&I customers as a natural expansion of our customer base from regulated utilities to medium and large C&I clients desiring to contract for renewable energy.

The advances in electricity storage technology together with high period demand charges, demand response programs, concern over electricity supply reliability and more aggressive goals for renewable energy content than those of centralized electricity suppliers are all factors that have supported the growth of the C&I market. The need for technical customized solutions to meet these varied C&I needs fits well with the expected acquisition of VEI’s business and assets and our experience in providing customized geothermal and REG solutions to various customers around the world.

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Solar PV

The market for Solar PV power grew significantly in recent years, driven by a combination of favorable government policies and a decline in equipment prices.  We are monitoring market drivers with the potential to develop Solar PV power plants in locations where we can offer competitively priced power generation. Our focus currently is on large-scale solar power plant development opportunities worldwide such as in: (i) Chile, where the total installed Solar PV capacity increased from 6 MW in 2013 to almost 1 GW by the end of 2015 and is currently considered the cheapest source of electricity in the country, (ii) Mexico, considered among the largest potential national markets in Latin America on the strength of high solar resources and recent energy market reform, (iii) India, where the central government recently gave its approval to ramp up India’s solar power capacity target to achieve 100 GW by 2022 (60 GW of grid connected solar power projects and 40 GW of rooftop solar) and (iv) the East Africa region, where a considerable amount of solar radiation and abundant available land constitute significant solar potential. Governments in the East Africa region have introduced various solar targets and incentives, which provide opportunities for installing grid-tied and off-grid Solar PV systems to displace fuel costs.

Competitive Strengths

Competitive Assets. We believe our assets are competitive for the following reasons:

• Contracted Generation. All of the electricity generated by our geothermal power plants is currently sold pursuant to long-term PPAs with an average remaining life of approximately 15 years.

• Baseload Generation. All of our geothermal power plants supply all or a part of the baseload capacity of the electric system in their respective markets. This means they supply electric power on an around-the-clock basis. This provides us with a competitive advantage over other renewable energy sources, such as wind power, solar power or hydro-electric power (to the extent they depend on precipitation), which cannot provide baseload capacity because of their intermittent nature. It remains to be seen whether developments in the energy storage markets will erode this competitive advantage.

• Ancillary Services. Geothermal power plants positively impact electrical grid stability and provide valuable ancillary services. Because of the baseload nature of their output, they have high transmission utilization efficiency, provide capacity, provide grid inertia and reduce the need for ancillary services such as voltage regulation, reserves and flexible capacity. Other intermittent renewables create integration costs, adding a significant value for geothermal energy.  

Competitive Pricing. Geothermal power plants, while site specific, are economically feasible in many locations, and the electricity they generate is generally price competitive under existing economic conditions and existing tax and regulatory regimes compared to electricity generated from fossil fuels or other renewable sources in many places around the world. Geothermal energy is recognized as one of the lower cost sources of energy from a LCOE perspective.

Ability to Finance Our Activities from Internally Generated Cash Flow. The cash flow generated by our portfolio of operating geothermal and REG power plants provides us with a robust and predictable base for certain exploration, development, and construction activities. We plan to evaluate various alternatives for financing the expansion of our business as we further develop and implement our new strategic plan.

Growing Legislative Demand for Environmentally-Friendly Renewable Resource Assets. Most of our currently operating power plants produce electricity from geothermal energy sources. The clean and sustainable characteristics of geothermal energy give us a competitive advantage over fossil fuel-based electricity generation as countries increasingly seek to balance environmental concerns with demands for reliable sources of electricity.

High Efficiency from Vertical Integration. Unlike our competitors in the geothermal industry, we are a fully integrated geothermal equipment, services, and power provider. We design, develop, and manufacture equipment that we use in our geothermal and REG power plants. Our intimate knowledge of the equipment that we use in our operations allows us to operate and maintain our power plants efficiently and to respond to operational issues in a timely and cost-efficient manner. Moreover, given the efficient communications among our subsidiary that designs and manufactures the products we use in our operations and our subsidiaries that own and operate our power plants, we are able to quickly and cost effectively identify and repair mechanical issues and to have technical assistance and replacement parts available to us as and when needed.

Exploration and Drilling Capabilities. We have in-house capabilities to explore and develop geothermal resources and have established a drilling operation that currently owns nine drilling rigs. We employ an experienced resource group that includes engineers, geologists, and drillers, which executes our exploration and drilling plans for projects that we develop.

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Highly Experienced Management Team. We have a highly qualified senior management team with extensive experience in the geothermal power sector.

Technological Innovation. We have 73 U.S. patents in force (and have approximately 16 U.S. patents pending) relating to various processes and renewable resource technologies. All of our patents are internally developed. Our ability to draw upon internal resources from various disciplines related to the geothermal power sector, such as geological expertise relating to reservoir management, and equipment engineering relating to power units, allows us to be innovative in creating new technologies and technological solutions.

Limited Exposure to Fuel Price Risk. A geothermal power plant does not need to purchase fuel (such as coal, natural gas, or fuel oil) in order to generate electricity. Thus, once the geothermal reservoir has been identified and estimated to be sufficient for use in a geothermal power plant, the drilling of wells is complete and the plant has a PPA, the plant is not exposed to fuel price or fuel delivery risk apart from the impact fuel prices may have on the price at which we sell power under PPAs that are based on the relevant power purchaser’s avoided costs.

Although we are confident in our competitive position in light of the strengths described above, we face various challenges in the course of our business operations, including as a result of the risks described in Item 1A — “Risk Factors” below, the trends and uncertainties discussed in “Trends and Uncertainties” under Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” below, and the competition we face in our different business segments described under “Competition” below.

Business Strategy

Our strategy is to continue building a geographically balanced portfolio of geothermal and recovered energy assets, and to continue to be a leader in the geothermal energy market with the objective of becoming a leading global provider of renewable energy. Since 2015, we have begun to implement a number of the elements of a new multi-year strategic plan.  We expect the plan to evolve over time in response to market conditions and other factors.  We intend to implement this strategy through:

• Development and Construction of New Geothermal Power Plants — continuously seeking out commercially exploitable geothermal resources, developing and constructing new geothermal power plants and entering into long-term PPAs providing stable cash flows in jurisdictions where the regulatory, tax and business environments encourage or provide incentives for such development;

• Expanding our geographical reach — increasing our business development activities in an effort to grow our business in the global markets in both business segments. While we continue to evaluate global opportunities, we currently see Mexico, Chile, Indonesia and Ethiopia as very attractive markets for us.  We are actively looking at ways to expand our presence in those countries.

• Acquisition of New Assets — expanding and accelerating growth through acquisition activities globally, aiming to acquire from third parties additional geothermal and Solar PV assets as well as companies that will expedite our entrance into the storage and C&I markets; For example, we recently announced that we will acquire substantially all of the assets and business of VEI, which has nearly a decade of expertise and leadership in demand response, energy management and storage. We expect that this acquisition will enable us to become a significant player in the growing energy storage and demand response markets and to diversify our traditional customer base with new C&I customers.

• Manufacturing and Providing Products and EPC Services Related to Renewable Energy — designing, manufacturing and contracting power plants for our own use and selling to third parties power units and other generation equipment for geothermal and recovered energy-based electricity generation;

• Expanding into New Technologies – leveraging our technological capabilities over a variety of renewable energy platforms, including solar power generation and energy storage.  Initially, however, we expect that our focus will be on expanding our core geothermal competencies, such as expanding into steam geothermal generation equipment and facilities.  For example, we announced a collaboration with Toshiba, which we anticipate may facilitate joint development of geothermal systems consisting of Ormat’s binary system and Toshiba’s flash system, among other things. We may acquire companies with integration and technological capabilities we do not currently have, or develop new technology ourselves, where we can effectively leverage our expertise to implement this part of our strategic plan.

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• Expand our customer base - evaluating a number of strategies for expanding our customer base to the C&I market.  In the near term, however, we expect that a majority of our revenues will continue to be generated as they now are, with our traditional electrical utility customer base for the Electricity segment.

• Increasing Output from Our Existing Power Plants — increasing output from our existing geothermal power plants by adding additional generating capacity, upgrading plant technology, and improving geothermal reservoir operations, including improving methods of heat source supply and delivery;

• Cost saving by increasing efficiencies — increasing efficiencies in our operating power plants and manufacturing facility including procurement by adding new technologies, restructuring of management control, automating part of our manufacturing work and centralizing our operating power plants.

• Technological Expertise — investing in research and development of renewable energy technologies and leveraging our technological expertise to continuously improve power plant components, reduce operations and maintenance costs, develop competitive and environmentally friendly products for electricity generation and target new service opportunities.

Recent Developments

The most significant recent developments in our company and business are described below.

● In February 2017, we decided to start construction to expand the Olkaria III complex in Kenya by an additional 10 MW and increase the complex's capacity to 150 MW during 2018.

● On January 3, 2017, we announced that on December 29, 2016, we entered into a definitive agreement to acquire substantially all of the business and assets of VEI, a privately held Philadelphia-based company with nearly a decade of expertise and leadership in demand response, energy management and storage. The transaction will mark Ormat’s entry into the growing energy storage and demand response markets, with an established North American presence. Initial consideration for the acquisition is $35 million which will be paid at closing and is subject to adjustment in certain cases. Additional contingent consideration will be payable in two installments subject to the achievement of certain performance milestones measured at the end of fiscal years 2017 and 2020. Closing is expected in early 2017.

● On December 19, 2016, we announced that we entered into a partnership transaction with a financial investor that allow us to efficiently monetize the federal tax incentives relating to five geothermal power plants located in eastern Nevada. The transaction involves the McGinness Hills geothermal power plant complex and the Tuscarora and Jersey Valley geothermal power plants which, prior to the transaction, were wholly owned by Ormat Nevada, as well as the Don A. Campbell phase 2 geothermal power plant which, prior to the transaction, was part of the ORPD portfolio jointly owned 63.25% by Ormat Nevada and 36.75% by Northleaf Geothermal Holdings LLC, an affiliate of Northleaf Capital Partners. As part of the transaction, the five geothermal power plants were transferred to a newly established limited liability company and the investor purchased membership interests in the limited liability company for an initial purchase price of $62.1 million and for which it will pay additional installments that are expected to amount to approximately $21 million through 2022. Ormat Nevada's share of the initial cash proceeds was $55.2 million.

● On December 21, 2016, we signed a $50 million loan facility agreement with DEG to refinance our investment in Plant 4 of the Olkaria III complex located in Kenya. The loan will mature in June 2028 and bear interest at a fixed annual rate of 6.28%. The loan will be payable in 20 equal principal payments starting in December 2018.

● On December 6, 2016, we announced that we signed a $36 million EPC contract with a subsidiary of Cyrq. Under the EPC contract, we will provide one air-cooled OEC at Cyrq’s Soda Lake geothermal power project in northern Nevada. The project is expected to come on line in 2018. The new OEC will increase generation and reduce operating costs by replacing the two currently operating power plants, which were commissioned by Ormat in the late 1980’s and early 1990’s, respectively.

● On November 30, 2016, we announced that we issued and sold $92.5 million aggregate principal amount of 4.03% Senior Secured Notes due 2033.  The Senior Secured Notes were issued in a private placement transaction exempt from the registration requirements of the Securities Act, and were all purchased by MEAG, the asset manager of Munich Re.  The Senior Secured Notes were assigned an investment grade rating of BBB- by Kroll Rating Agency. We issued the Senior Secured Notes to refinance the costs of development and construction of the first phase of the Don A. Campbell (DAC 1) geothermal power plant, which Ormat initially financed using equity funding.  The DAC 1 power plant is part of the ORPD portfolio.  Our share of the proceeds, net of transaction fees and funding of a debt service reserve account was approximately $55.0 million.

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● On November 29, 2016, we announced that we entered into a 25-year PPA with SCPPA to deliver electricity from our Ormesa geothermal complex in Imperial Valley, California beginning November 30, 2017. The SCPPA PPA will supersede Ormesa’s current 30-year SO#4 with Southern California Edison that has a variable energy rate tied primarily to volatile natural gas prices and that will expire on November 29, 2017. Under the terms of the PPA, energy from the Ormesa complex will be sold to SCPPA at a rate of $77.25 per MWh with no annual escalation. Contract capacity is 35 MW, with a maximum generation equivalent to a net capacity of about 43 MW. SCPPA will resell about 86% of the Ormesa power plants complex’s output to the LADWP and the remaining 14% to the IID.

● On November 23, 2016, we announced that we closed a follow-on equity transaction with Northleaf. Northleaf purchased a 36.75% equity interest in the second phase of the Don A. Campbell power plant for a purchase price of $44.2 million. The 20.5 MW second phase of the Don A. Campbell geothermal power plant commenced operation in September 2015 and sells its electricity to SCPPA under a 20-year PPA. Following the closing, the power plant was contributed to the existing ORPD portfolio under the terms of ORPD's limited liability company agreement executed by Ormat and Northleaf on April 30, 2015, and then further contributed to Opal, as described above.

● On September 11, 2016, we announced that we concluded an auction tender and accepted subscriptions for $204 million aggregate principal amount of two tranches (approximately $67 million principal amount of Series 2 and approximately $137 million principal amount of Series 3) of senior unsecured bonds (“Series 2 Bonds”, “Series 3 Bonds” and, collectively, “Bonds”). The Bonds were issued in an unregistered offering outside the United States to investors who are not "U.S. persons", as such term is defined in Regulation S under the Securities Act, and otherwise subject to the requirements of Regulation S. The Series 2 Bonds will mature in September 2020 and bear interest at a fixed rate of 3.7% per annum, payable semi-annually.  The Series 3 Bonds will mature in September 2022 and bear interest at a fixed rate of 4.45% per annum, payable semi-annually. The Bonds will be repaid at maturity in a single bullet payment, unless earlier prepaid by Ormat pursuant to the terms and conditions of the trust instrument that governs the Bonds. Both tranches received a rating of ilA+ from Maloot S&P in Israel with a stable outlook. We used the proceeds from the offering and sale of the Bonds to prepay existing indebtedness, including prepayment fees of approximately $5 million. We expects our annual interest expense to decrease as a result of this refinancing.

● On August 30, 2016, we announced that we reached an agreement in principle on a proposed settlement with certain former employees of the Company to settle claims brought by such employees against the Company under the qui tam provisions of the False Claims Act. The agreement in principle provides that we make no admission of wrongdoing, and for the release and the dismissal of all claims alleged in the complaint. The settlement agreement was executed on October 25, 2016 and payment of the $11 million settlement was made within 10 days thereafter. Upon payment, the court was provided a joint stipulation for dismissal of the case with prejudice.

● In July 2016, we announced that we closed the previously announced acquisition of Geothermie Bouillante SA (GB). GB owns and operates the 14.75 MW Bouillante geothermal power plant located in Guadeloupe Island, a French territory in the Caribbean, which currently generates approximately 13 MW. GB also owns two exploration licenses providing an expansion potential of up to 45 MW of capacity.

Pursuant to the terms of an Amended and Restated Investment Agreement (Investment Agreement) and Shareholders Agreement with Sageos Holding (Sageos), a wholly owned subsidiary of Bureau de Recherches Géologiques et Minières (BRGM), Ormat together with Caisse des Dépôts et Consignations (CDC), a French state-owned financial organization, acquired an approximately 80% interest in GB allocated 75% to Ormat and 25% to CDC. Ormat and CDC will gradually increase their combined interest in GB to 85% and Sageos will hold the remaining balance.

Pursuant to the agreements, we paid approximately $20.6 million (approximately €18.5 million) to Sageos for approximately 60% interest in GB. In addition, we are committed to further invest $8.4 million (approximately €7.5 million) by July 2018, which will increase our interest to 63.75%. The cash will be used mainly for the enhancement of the power plant.

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We have planned modifications to the existing equipment as well as to further develop the asset, with a potential of reaching a total of 45 MW in phased development by 2021. Under the Investment Agreement, we will pay Sageos an additional amount of up to $13.4 million (approx. €12 million) subject to the achievement of agreed production thresholds and capacity expansion within a defined time period.

Bouillante power plant sells its electricity under a 15-year PPA that was entered into in February 2016 with Électricité de France S.A. (EDF), the French electric utility. We plan to optimize the use of the resource at the existing facilities and recover its current production to its design capacity of 14.75 MW by mid-2017. Upon completion of the enhancement, the plant is expected to generate approximately $22.3 million (approximately €20 million) of annual revenues.

● On June 28, 2016, we announced that construction was completed at the Veyo Heat Recovery Project in southern Utah. This project was constructed pursuant to a $22.3 million EPC contract signed with Utah Associated Municipal Power Systems (UAMPS) in November 2014, and comprises an air-cooled REG unit at UAMPS’ Kern River Gas Transmission (Kern River) Veyo natural gas compressor station. The project uses an OEC to generate power from heat that otherwise would have been released into the atmosphere. The Veyo REG project was brought online May 26, 2016, a full four months ahead of schedule.

● On May 19, 2016, we signed supply and EPC contracts worth approximately $36 million with Eastland Group for the Te Ahi O Maui geothermal project located near Kawerau, New Zealand. Under the supply and EPC contracts, Ormat will provide its air-cooled OEC for the project. This project is a partnership between Eastland Generation and the Kawerau AD Ahu Whenua Trust, who are the owners of the land on which the project will be constructed. The construction of the project is expected to be completed in the first half of 2018.

● On March 30, 2016, we announced that we signed an agreement with a subsidiary of Alevo Group SA, a leading provider of energy storage systems, to jointly build, own and operate the Rabbit Hill Energy Storage Project (Rabbit Hill), located in Georgetown, Texas. We will own and fund the majority of the 10 MW Rabbit Hill energy storage project and under the terms of the agreements, will provide engineering and construction services and balance of plant equipment. Alevo will provide its innovative GridBank®„¢ inorganic lithium ion energy storage system in conjunction with the power conversion systems. In addition, Alevo will provide ongoing management and operations and maintenance services for the life of the project. The project will consist of three GridBank®„¢ enclosures and will provide fast responding regulation services (FRRS) as an open market participant in the Electric Reliability Council of Texas (ERCOT), an independent system operator that manages the flow of electric power to Texas customers.

● On February 3, 2016, we announced that we commenced commercial operation of Plant 4 in the Olkaria III complex in Kenya, increasing the complex total generating capacity by 29 MW to 139 MW. Plant 4 will sell its electricity to KPLC under a 20-year PPA. In October 2015, Ormat signed an amendment to the PPA with KPLC that enables the increase of the capacity of Plant 4 expansions to an aggregate of 100 MW, in phases. Plant 4 was financed by Ormat equity which is covered by an insurance policy from MIGA (a member of the World Bank Group) to cover Ormat’s exposure to certain political risks involved in operating in developing countries.

● On January 12, 2016, we announced that we commenced construction of the 35 MW Platanares geothermal project in Honduras. In 2013, Ormat signed a BOT contract for the Geotérmica Platanares geothermal project in Honduras with ELCOSA, a privately owned Honduran energy company, for approximately 15 years from the COD. The Platanares project will sell its power, mainly under 30-year PPA with the national utility of Honduras, ENEE. We expect the project to reach commercial operation by the end of 2017 and generate average annual revenues of approximately $33 million.

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Operations of our Electricity Segment

How We Own Our Power Plants. We customarily establish a separate subsidiary to own interests in each power plant. Our purpose in establishing a separate subsidiary for each plant is to ensure that the plant, and the revenues generated by it, will be the only source for repaying indebtedness, if any, incurred to finance the construction or the acquisition (or to refinance the construction or acquisition) of the relevant plant. If we do not own all of the interest in a power plant, we enter into a shareholders agreement or a partnership agreement that governs the management of the specific subsidiary and our relationship with our partner in connection with the specific power plant. Our ability to transfer or sell our interest in certain power plants may be restricted by certain purchase options or rights of first refusal in favor of our power plant partners or the power plant’s power purchasers and/or certain change of control and assignment restrictions in the underlying power plant and financing documents. All of our domestic geothermal and REG power plants are Qualifying Facilities under the PURPA, and are eligible for regulatory exemptions from most provisions of the FPA and certain state laws and regulations.

How We Explore and Evaluate Geothermal Resources. Since 2006, we have expanded our exploration activities, initially in the U.S. and more recently with an increasing focus internationally. It normally takes two to three years from the time we start active exploration of a particular geothermal resource to the time we have an operating production well, assuming we conclude the resource is commercially viable and determine to pursue its development. Exploration activities generally involve the phases described below.

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Initial Evaluation. Identifying and evaluating potential geothermal resources by sampling and studying new areas combined with information available from public and private sources. We generally adhere to the following process, although our process can vary from site to site depending on geological circumstances and prior evaluation:

• We evaluate historic, geologic and geothermal information available from public and private databases, including geothermal, mining, petroleum and academic sources.

• We visit sites, sampling fluids for chemistry if necessary, to evaluate geologic conditions.

• We evaluate available data, and rank prospects in a database according to estimated size and perceived risk. For example, pre-drilled sites with extensive data are considered lower risk than “green field” sites. Both prospect types are considered critical for Ormat’s continued growth.

• We generally create a digital, spatial geographic information systems (GIS) database and 3D geologic model containing all pertinent information, including thermal water temperature gradients derived from historic drilling, geologic mapping information (e.g., formations, structure, alteration, and topography), and any available archival information about the geophysical properties of the potential resource.

• We assess other relevant information, such as infrastructure (e.g., roads and electric transmission lines), natural features (e.g., springs and lakes), and man-made features (e.g., old mines and wells).

Our initial evaluation is usually conducted by our own staff, although we might engage outside service providers for some tasks from time to time. The costs associated with an initial evaluation vary from site to site, based on various factors, including the acreage involved and the costs, if any, of obtaining information from private databases or other sources. On average, our expenses for an initial evaluation range from approximately $10,000 to $50,000 including travel, chemical analyses, and data acquisition.

If we conclude, based on the information considered in the initial evaluation, that the geothermal resource could support a commercially viable power plant, taking into account various factors described below, we proceed to land rights acquisition.

Land Acquisition. Acquiring land rights to any geothermal resources our initial evaluation indicates could potentially support a commercially viable power plant, taking into account various factors. For domestic power plants, we either lease or own the sites on which our power plants are located. For our foreign power plants, our lease rights for the plant site are generally contained in the terms of a concession agreement or other contract with the host government or an agency thereof. In certain cases, we also enter into one or more geothermal resource leases (or subleases) or a concession or an option agreement or other agreement granting us the exclusive right to extract geothermal resources from specified areas of land, with the owners (or sublessors) of such land. In some cases we obtain first the exploration license and once certain investment requirements are met, we can obtain the exploitation rights. This usually gives us the right to explore, develop, operate, and maintain the geothermal field, including, among other things, the right to drill wells (and if there are existing wells in the area, to alter them) and build pipelines for transmitting geothermal fluid. In certain cases, the holder of rights in the geothermal resource is a governmental entity and in other cases a private entity. Usually the duration of the lease (or sublease) and concession agreement corresponds to the duration of the relevant PPA, if any. In certain other cases, we own the land where the geothermal resource is located, in which case there are no restrictions on its utilization. Leasehold interests in federal land in the U.S. are regulated by the BLM and the Minerals Management Service. These agencies have rules governing the geothermal leasing process as discussed below under “Description of Our Leases and Lands”.

For most of our current exploration sites in the U.S., we acquire rights to use geothermal resource through land leases with the BLM, with various states, or through private leases. Under these leases, we typically pay an up-front non-refundable bonus payment, which is a component of the competitive lease process. In addition, we undertake to pay nominal, fixed annual rent payments for the period from the commencement of the lease through the completion of construction. Upon the commencement of power generation, we begin to pay to the lessors long-term royalty payments based on the use of the geothermal resources as defined in the respective agreements. These payments are contingent on the power plant’s revenues. A summary of our typical lease terms is provided below under “Description of our Leases and Lands”.

The up-front bonus and royalty payments vary from site to site and are based, among other things, on current market conditions.

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Surveys. Conducting geological, geochemical, and/or geophysical surveys on the sites acquired. Following the acquisition of land rights for a potential geothermal resource, we conduct additional surface water analyses, soil surveys, and geologic mapping to determine proximity to possible heat flow anomalies and up-flow/permeable zones. We augment our digital database with the results of those analyses and create conceptual and digital geologic models to describe geothermal system controls. We then initiate a suite of geophysical surveys (e.g., gravity, magnetics, resistivity, magnetotellurics, reflection seismic, LiDAR, and spectral surveys) to assess surface and sub-surface structure (e.g., faults and fractures) and improve the geologic model of fluid-flow conduits and permeability controls. All pertinent geological and geophysical data are used to create three-dimensional geologic models to identify drill locations. These surveys are conducted incrementally considering relative impact and cost, and the geologic model is updated continuously.

We make a further determination of the commercial viability of the geothermal resource based on the results of this process, particularly the results of the geochemical surveys estimating temperature and the overall geologic model, including potential resource size. If the results from the geochemical surveys are poor (i.e., low derived resource temperatures or poor permeability) or the geologic model indicates small or deep resource, we re-evaluate the commercial viability of the geothermal resource and may not proceed to exploratory drilling. We generally only move forward with those sites that we believe have a high probability for development.

Exploratory Drilling. Drilling one or more exploratory wells on the high priority, relatively low risk sites to confirm and/or define the geothermal resource. If we proceed to exploratory drilling, we generally use outside contractors to create access roads to drilling sites and related activities. We have continued efforts to reduce exploration costs and therefore, after obtaining drilling permits, we generally drill temperature gradient holes and/or core holes that are lower cost than slim holes (used in the past) using either our own drilling equipment, whenever possible, or outside contractors. If the obtained data supports a conclusion that the geothermal resource can support a commercially viable power plant, it will be used as an observation well to monitor and define the geothermal resource. If the core hole indicates low temperatures or does not support the geologic model of anticipated permeability, it may be plugged and the area reclaimed. In undrilled sites, we typically step up from shallow (500-1000 ft) to deeper (2000-4000 ft) wells as confidence improves. Following proven temperature in core wells, we typically move to slim and/or full size wells to quantify permeability.

Each year we determine and approve an exploration budget for the entire exploration activity in such year. We prioritize budget allocation between the various geothermal sites based on commercial and geological factors. The costs we incur for exploratory drilling vary from site to site based on various factors, including the accessibility of the drill site, the geology of the site, and the depth of the resource. However, on average, exploration costs, prior to drilling of a full-size well are approximately $1.0 million to $3.0 million for each site, not including land acquisition. However, we only reach such spending levels for sites that proved to be successful in the early stages of the exploration.

At various points during our exploration activities, we re-assess whether the geothermal resource involved will support a commercially viable power plant based on information available at that time. Among other things, we consider the following factors:

• New data and interpretations obtained concerning the geothermal resource as our exploration activities proceed, and particularly the expected MW capacity power plant the resource can be expected to support. The MW capacity can be estimated using analogous systems and/or quantitative heat in place estimates until results from drilling and flow tests quantify temperature, permeability, and resulting resource size.

• Current and expected market conditions and rates for contracted and merchant electric power in the market(s) to be serviced.

• Availability of transmission capacity.

• Anticipated costs associated with further exploration activities and the relative risk of failure.

• Anticipated costs for design and construction of a power plant at the site.

• Anticipated costs for operation of a power plant at the site, particularly taking into account the ability to share certain types of costs (such as control rooms) with one or more other power plants that are, or are expected to be, operating near the site.

If we conclude that the geothermal resource involved will support a commercially viable power plant, we proceed to constructing a power plant at the site.

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How We Construct Our Power Plants. The principal phases involved in constructing one of our geothermal power plants are as follows:

• Drilling production and injection wells.

• Designing the well field, power plant, equipment, controls, and transmission facilities.

• Obtaining any required permits, electrical interconnection and transmission agreements.

• Manufacturing (or in the case of equipment we do not manufacture ourselves, purchasing) the equipment required for the power plant.

• Assembling and constructing the well field, power plant, transmission facilities, and related facilities.

It generally takes approximately two years from the time we drill a production well, until the power plant becomes operational.

Drilling Production and Injection Wells. We consider completing the drilling of first production well as the beginning of our construction phase for a power plant. However, it is not always sufficient for a full release for construction. The number of production wells varies from plant to plant depending, among other things, on the geothermal resource, the projected capacity of the power plant, the power generation equipment to be used and the way geothermal fluids will be re-injected through injection wells to maintain the geothermal resource and surface conditions. We generally drill the wells ourselves although in some cases we use outside contractors.

The cost for each production and injection well varies depending, among other things, on the depth and size of the well and market conditions affecting the supply and demand for drilling equipment, labor and operators. Our typical cost for each production and injection well is approximately $4.0 million with a range of $1.0 million to $10.0 million.

Design. We use our own employees to design the well field and the power plant, including equipment that we manufacture and that will be needed for the power plant. The designs vary based on various factors, including local laws, required permits, the geothermal resource, the expected capacity of the power plant and the way geothermal fluids will be re-injected to maintain the geothermal resource and surface conditions.

Permits. We use our own employees and outside consultants to obtain any required permits and licenses for our power plants that are not already covered by the terms of our site leases. The permits and licenses required vary from site to site, and are described below under “Environmental Permits”.

Manufacturing. Generally, we manufacture most of the power generating unit equipment we use at our power plants. Multiple sources of supply are generally available for all other equipment we do not manufacture.

Construction. We use our own employees to manage the construction work. For site grading, civil, mechanical, and electrical work we use subcontractors.

During fiscal year 2016, in the Electricity segment, we focused on the commencement of operations at Olkaria III plant 4. We continued with construction of the Platanares project in Honduras and began construction of the Tungsten and Dixie Meadows projects in Nevada. During fiscal year 2015, we focused on the commencement of operations at the McGinness Hills phase 2 and the Don A. Campbell phase 2 power plants. We continued with construction of Olkaria III plant 4. During fiscal year 2014, we began construction of the Don A. Campbell phase 2 power plant and Olkaria III plant 4.

When deciding whether to continue holding lease rights and/or to pursue exploration activity, we diligently prioritize our prospective investments, taking into account resource and probability assessments in order to make informed decisions about whether a particular project will support commercial operations. As a result, during fiscal year 2016, we discontinued exploration activities at three future prospects, including Kula in Hawaii, Aqua quieta and sollipulli in Chile. During fiscal year 2015, we discontinued exploration and development activities at ten future prospects, including Kona and Ulupalakua (Maui) in Hawaii, Warm Springs Tribe and Newberry - Twilight in Oregon, Whirlwind Valley in Utah, Argenta, Hycroft and South Jersey in Nevada and Mariman and Quinohuen in Chile. During fiscal year 2014, we discontinued exploration and development activities at seven exploration sites and one development project, including Huu Dumpo in Indonesia, Mount Spurr in Alaska, San Pablo, San Jose II, and Aroma in Chile, Silver Lake, Summer Lake and Foley Hot Springs in Oregon and Wister in California.

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After conducting exploratory studies at those sites, we concluded that the respective geothermal resources would not support commercial operations. Costs associated with exploration activities at these sites were expensed accordingly (see “Write-off of Unsuccessful Exploration Activities” under Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations”).

We added to our exploration activities ten sites in each of the years ended December 31, 2016 and 2015 and four sites during the years ended December 31, 2014.

How We Operate and Maintain Our Power Plants. In the U.S. we usually employ our subsidiary, Ormat Nevada, to act as operator of our power plants pursuant to the terms of an operation and maintenance agreement. Operation and maintenance of our foreign projects are generally provided by our subsidiary that owns the relevant project. Our operations and maintenance practices are designed to minimize operating costs without compromising safety or environmental standards while maximizing plant flexibility and maintaining high reliability. Our operations and maintenance practices for geothermal power plants seek to preserve the sustainable characteristics of the geothermal resources we use to produce electricity and maintain steady-state operations within the constraints of those resources reflected in our relevant geologic and hydrologic studies. Our approach to plant management emphasizes the operational autonomy of our individual plant or complex managers and staff to identify and resolve operations and maintenance issues at their respective power plants; however each power plant or complex draws upon our available collective resources and experience, and that of our subsidiaries. We have organized our operations such that inventories, maintenance, backup, and other operational functions are pooled within each power plant complex and provided by one operation and maintenance provider. This approach enables us to realize cost savings and enhances our ability to meet our power plant availability goals.

Safety is a key area of concern to us. We believe that the most efficient and profitable performance of our power plants can only be accomplished within a safe working environment for our employees. Our compensation and incentive program includes safety as a factor in evaluating our employees, and we have a well-developed reporting system to track safety and environmental incidents, if any, at our power plants.

How We Sell Electricity. In the U.S., the purchasers of power from our power plants are typically investor-owned electric utility companies or electric cooperatives. Outside of the U.S., the purchaser is either a state-owned utility or a privately-owned entity and we typically operate our facilities pursuant to rights granted to us by a governmental agency pursuant to a concession agreement. In each case, we enter into long-term contracts (typically, PPAs) for the sale of electricity or the conversion of geothermal resources into electricity. Although previously a power plant’s revenues under a PPA generally consisted of two payments — energy payments and capacity payments, our recent PPAs provide for energy payments only. Energy payments are normally based on a power plant’s electrical output actually delivered to the purchaser measured in kilowatt hours, with payment rates either fixed or indexed to the power purchaser’s “avoided” power costs (i.e., the costs the power purchaser would have incurred itself had it produced the power it is purchasing from third parties) or rates that escalate at a predetermined percentage each year. Capacity payments are normally calculated based on the generating capacity or the declared capacity of a power plant available for delivery to the purchaser, regardless of the amount of electrical output actually produced or delivered. In addition, most of our domestic power plants located in California are eligible for capacity bonus payments under the respective PPAs upon reaching certain levels of generation, or subject to a capacity payment reduction if certain levels of generation are not reached.

How We Finance Our Power Plants. Historically we have funded our power plants with a different sources of liquidity such as a combination of non-recourse or limited recourse debt, including lease financing, tax monetization transactions, internally generated cash, which includes funds from operation, as well as proceeds from loans under corporate credit facilities, sale of securities, and sale of membership interests. Such leveraged financing permits the development of power plants with a limited amount of equity contributions, but also increases the risk that a reduction in revenues could adversely affect a particular power plant’s ability to meet its debt obligations. Leveraged financing also means that distributions of dividends or other distributions by plant subsidiaries to us are contingent on compliance with financial and other covenants contained in the financing documents.

Non-recourse debt or lease financing refers to debt or lease arrangements involving debt repayments or lease payments that are made solely from the power plant’s revenues (rather than our revenues or revenues of any other power plant) and generally are secured by the power plant’s physical assets, major contracts and agreements, cash accounts and, in many cases, our ownership interest in our affiliate that owns that power plant. These forms of financing are referred to as “project financing”. Project financing transactions generally are structured so that all revenues of a power plant are deposited directly with a bank or other financial institution acting as escrow or security deposit agent. These funds are then payable in a specified order of priority set forth in the financing documents to ensure that, to the extent available, they are used to first pay operating expenses, senior debt service (including lease payments) and taxes, and to fund reserve accounts. Thereafter, subject to satisfying debt service coverage ratios and certain other conditions, available funds may be disbursed for management fees or dividends or, where there are subordinated lenders, to the payment of subordinated debt service.

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In the event of a foreclosure after a default, our affiliate that owns the power plant would only retain an interest in the assets, if any, remaining after all debts and obligations have been paid in full. In addition, incurrence of debt by a power plant may reduce the liquidity of our equity interest in that power plant because the equity interest is typically subject both to a pledge in favor of the power plant’s lenders securing the power plant’s debt and to transfer and change of control restrictions set forth in the relevant financing agreements.

Limited recourse debt refers to project financing as described above with the addition of our agreement to undertake limited financial support for our affiliate that owns the power plant in the form of certain limited obligations and contingent liabilities. These obligations and contingent liabilities may take the form of guarantees of certain specified obligations, indemnities, capital infusions and agreements to pay certain debt service deficiencies. To the extent we become liable under such guarantees and other agreements in respect of a particular power plant, distributions received by us from other power plants and other sources of cash available to us may be required to be used to satisfy these obligations. Creditors of a project financing of a particular power plant may have direct recourse to us to the extent of these limited recourse obligations.

We have also used financing structures to monetize PTCs, such as our recently announced Opal tax partnership transaction, and other favorable tax benefits derived from the financed power plants and an operating lease arrangement for our Puna complex power plants.

We have recently used a sale of membership interests in two of our geothermal assets and nine of our REG facilities to fund corporate needs including funds for the construction of new projects. We may use such financing structure in the future.

How We Mitigate International Political Risk. We generally purchase insurance policies to cover our exposure to certain political risks involved in operating in developing countries, as described below under “Insurance”. To date, our political risk insurance policies are with the Multilateral Investment Guaranty Agency (MIGA), a member of the World Bank Group, and Zurich Re, a private insurance and re-insurance company. Such insurance policies generally cover, subject to the limitations and restrictions contained therein, 80-90% of our losses resulting from a specified governmental act such as confiscation, expropriation, riots, the inability to convert local currency into hard currency, and, in certain cases, the breach of agreements. We have obtained such insurance for the Olkaria, Zunil and Sarulla projects.

Description of Our Leases and Lands

We have domestic leases on approximately 320,800 acres of federal, state, and private land in California, Hawaii, Nevada, New Mexico, Utah and Oregon. The approximate breakdown between federal, state, private leases and owned land is as follows:

• 85% are acres under our control are leased from the U.S. government, acting through the BLM;

• 11% are leases with private landowners and/or leaseholders;

• 2% are owned by us; and

• the balance are leases with various states, none of which is currently material.

Each of the leases within each of the categories has standard terms and requirements, as summarized below. Internationally, our land position includes approximately 196,200 acres, most of which are for geothermal prospects in Honduras and Indonesia.

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BLM Geothermal Leases

Certain of our domestic project subsidiaries have entered into geothermal resources leases with the U.S. government, pursuant to which they have obtained the right to conduct their geothermal development and operations on federally-owned land. These leases are made pursuant to the Geothermal Steam Act and the lessor under such leases is the U.S. government, acting through the BLM.

BLM geothermal leases grant the geothermal lessee the right and privilege to drill for, extract, produce, remove, utilize, sell, and dispose of geothermal resources on certain lands, together with the right to build and maintain necessary improvements thereon. The actual ownership of the geothermal resources and other minerals beneath the land is retained in the federal mineral estate. The geothermal lease does not grant to the geothermal lessee the exclusive right to develop the lands, although the geothermal lessee does hold the exclusive right to develop geothermal resources within the lands. The geothermal lessee does not have the right to develop minerals unassociated with geothermal production and cannot prohibit others from developing the minerals present in the lands. The BLM may grant multiple leases for the same lands and, when this occurs, each lessee is under a duty to not unreasonably interfere with the development rights of the other. Because BLM leases do not grant to the geothermal lessee the exclusive right to use the surface of the land, BLM may grant rights to others for activities that do not unreasonably interfere with the geothermal lessee’s uses of the same land; such other activities may include recreational use, off-road vehicles, and/or wind or solar energy developments.

Certain BLM leases issued before August 8, 2005 include covenants that require the projects to conduct their operations under the lease in a workmanlike manner and in accordance with all applicable laws and BLM directives and to take all mitigating actions required by the BLM to protect the surface of and the environment surrounding the land. Additionally, certain leases contain additional requirements, some of which concern the mitigation or avoidance of disturbance of any antiquities, cultural values or threatened or endangered plants or animals, the payment of royalties for timber, and the imposition of certain restrictions on residential development on the leased land.

BLM leases entered into after August 8, 2005 require the geothermal lessee to conduct operations in a manner that minimizes impacts to the land, air, water, to cultural, biological, visual, and other resources, and to other land uses or users. The BLM may require the geothermal lessee to perform special studies or inventories under guidelines prepared by the BLM. The BLM reserves the right to continue existing leases and to authorize future uses upon or in the leased lands, including the approval of easements or rights-of-way. Prior to disturbing the surface of the leased lands, the geothermal lessee must contact the BLM to be apprised of procedures to be followed and modifications or reclamation measures that may be necessary. Subject to BLM approval, geothermal lessees may enter into unit agreements to cooperatively develop a geothermal resource. The BLM reserves the right to specify rates of development and to require the geothermal lessee to commit to a communalization or unitization agreement if a common geothermal resource is at risk of being overdeveloped.

Typical BLM leases issued to geothermal lessees before August 8, 2005 have a primary term of ten years and will renew so long as geothermal resources are being produced or utilized in commercial quantities, but cannot exceed a period of forty years after the end of the primary term. If at the end of the forty-year period geothermal steam is still being produced or utilized in commercial quantities and the lands are not needed for other purposes, the geothermal lessee will have a preferential right to renew the lease for a second forty-year term, under terms and conditions as the BLM deems appropriate.

BLM leases issued after August 8, 2005 have a primary term of ten years. If the geothermal lessee does not reach commercial production within the primary term, the BLM may grant two five-year extensions if the geothermal lessee: (i) satisfies certain minimum annual work requirements prescribed by the BLM for that lease, or (ii) makes minimum annual payments. Additionally, if the geothermal lessee is drilling a well for the purposes of commercial production, the primary term (as it may have been extended) may be extended for five years and as long thereafter as steam is being produced and used in commercial quantities (meaning the geothermal lessee either begins producing geothermal resources in commercial quantities or has a well capable of producing geothermal resources in commercial quantities and is making diligent efforts to utilize the resource) for thirty-five years. If, at the end of the extended thirty-five year term, geothermal steam is still being produced or utilized in commercial quantities and the lands are not needed for other purposes, the geothermal lessee will have a preferential right to renew the lease for fifty-five years, under terms and conditions as the BLM deems appropriate.

For BLM leases issued before August 8, 2005, the geothermal lessee is required to pay an annual rental fee (on a per acre basis), which escalates according to a schedule described therein, until production of geothermal steam in commercial quantities has commenced. After such production has commenced, the geothermal lessee is required to pay royalties (on a monthly basis) on the amount or value of (i) steam, (ii) by-products derived from production, and (iii) commercially de-mineralized water sold or utilized by the project (or reasonably susceptible to such sale or use).

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For BLM leases issued after August 8, 2005, (i) a geothermal lessee who has obtained a lease through a non-competitive bidding process will pay an annual rental fee equal to $1.00 per acre for the first ten years and $5.00 per acre each year thereafter; and (ii) a geothermal lessee who has obtained a lease through a competitive process will pay a rental equal to $2.00 per acre for the first year, $3.00 per acre for the second through tenth year and $5.00 per acre each year thereafter. Rental fees paid before the first day of the year for which the rental is owed will be credited towards royalty payments for that year. For BLM leases issued, effective, or pending on August 5, 2005 or thereafter, royalty rates are fixed between 1.0-2.5% of the gross proceeds from the sale of electricity during the first ten years of production under the lease. The royalty rate set by the BLM for geothermal resources produced for the commercial generation of electricity but not sold in an arm’s length transaction is 1.75% for the first ten years of production and 3.5% thereafter. The royalty rate for geothermal resources sold by the geothermal lessee or an affiliate in an arm’s length transaction is 10.0% of the gross proceeds from the arm’s length sale. The BLM may readjust the rental or royalty rates at not less than twenty year intervals beginning thirty-five years after the date geothermal steam is produced.

In the event of a default under any BLM lease, or the failure to comply with any of the provisions of the Geothermal Steam Act or regulations issued under the Geothermal Steam Act or the terms or stipulations of the lease, the BLM may, 30 days after notice of default is provided to the relevant project, (i) suspend operations until the requested action is taken, or (ii) cancel the lease.

Private Geothermal Leases

Certain of our domestic project subsidiaries have entered into geothermal resources leases with private parties, pursuant to which they have obtained the right to conduct their geothermal development and operations on privately owned land. In many cases, the lessor under these private geothermal leases owns only the geothermal resource and not the surface of the land.

Typically, the leases grant our project subsidiaries the exclusive right and privilege to drill for, produce, extract, take and remove from the leased land water, brine, steam, steam power, minerals (other than oil), salts, chemicals, gases (other than gases associated with oil), and other products produced or extracted by such project subsidiary. The project subsidiaries are also granted certain non-exclusive rights pertaining to the construction and operation of plants, structures, and facilities on the leased land. Additionally, the project subsidiaries are granted the right to dispose geothermal fluid as well as the right to re-inject into the leased land water, brine, steam, and gases in a well or wells for the purpose of maintaining or restoring pressure in the productive zones beneath the leased land or other land in the vicinity. Because the private geothermal leases do not grant to the lessee the exclusive right to use the surface of the land, the lessor reserves the right to conduct other activities on the leased land in a manner that does not unreasonably interfere with the geothermal lessee’s uses of the same land, which other activities may include agricultural use (farming or grazing), recreational use and hunting, and/or wind or solar energy developments.

The leases provide for a term consisting of a primary term in the range of five to 30 years, depending on the lease, and so long thereafter as lease products are being produced or the project subsidiary is engaged in drilling, extraction, processing, or reworking operations on the leased land.

As consideration under most of our project subsidiaries’ private leases, the project subsidiary must pay to the lessor a certain specified percentage of the value “at the well” (which is not attributable to the enhanced value of electricity generation), gross proceeds, or gross revenues of all lease products produced, saved, and sold on a monthly basis. In certain of our project subsidiaries’ private leases, royalties payable to the lessor by the project subsidiary are based on the gross revenues received by the lessee from the sale or use of the geothermal substances, either from electricity production or the value of the geothermal resource “at the well”.

In addition, pursuant to the leases, the project subsidiary typically agrees to commence drilling, extraction or processing operations on the leased land within the primary term, and to conduct such operations with reasonable diligence until lease products have been found, extracted and processed in quantities deemed “paying quantities” by the project subsidiary, or until further operations would, in such project subsidiary’s judgment, be unprofitable or impracticable. The project subsidiary has the right at any time within the primary term to terminate the lease and surrender the relevant land. If the project subsidiary has not commenced any such operations on said land (or on the unit area, if the lease has been unitized), or terminated the lease within the primary term, the project subsidiary must pay to the lessor, in order to maintain its lease position, annually in advance, a rental fee until operations are commenced on the leased land.

If the project subsidiary fails to pay any installment of royalty or rental when due and if such default continues for a period of fifteen days specified in the lease, for example, after its receipt of written notice thereof from the lessor, then at the option of the lessor, the lease will terminate as to the portion or portions thereof as to which the project subsidiary is in default. If the project subsidiary defaults in the performance of any obligations under the lease, other than a payment default, and if, for a period of 90 days after written notice is given to it by the lessor of such default, the project subsidiary fails to commence and thereafter diligently and in good faith take remedial measures to remedy such default, the lessor may terminate the lease.

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We do not regard any property that we lease as material unless and until we begin construction of a power plant on the property, that is, until we drill a production well on the property.

Description of Our Power Plants

Domestic Operating Power Plants

The following descriptions summarize certain industry metrics for our domestic operating power plants:

Brady Complex

Location	Churchill County, Nevada
Generating Capacity	18 MW
Number of Power Plants	Two (Brady and Desert Peak 2 power plants).
Technology	The Brady complex utilizes binary and flash systems. The complex uses air and water-cooled systems.
Subsurface Improvements	12 production wells and eight injection wells are connected to the plants through a gathering system.
Major Equipment	Three OEC units and three steam turbines along with the Balance of Plant equipment.
Age	The Brady power plant commenced commercial operation in 1992 and a new OEC unit was added in 2004. The Desert Peak 2 power plant commenced commercial operation in 2007.
Land and Mineral Rights	The Brady complex is comprised mainly of BLM leases. The leases are held by production. The scheduled expiration dates for all of these leases are after the end of the expected useful life of the power plants. The complex’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described in “Description of Our Leases and Lands”.
Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases, and the Brady power plant holds rights of way from the BLM and from the private owner that allows access to and from the plant.
Resource Information	The resource temperatures at Brady and Desert Peak 2 are 270 degrees Fahrenheit and 338 degrees Fahrenheit, respectively.
	The Brady and Desert Peak geothermal systems are located within the Hot Springs Mountains, approximately 60 miles northeast of Reno, Nevada, in northwestern Churchill County. The dominant geological feature of the Brady area is a linear NNE-trending band of hot ground that extends two miles. The Desert Peak geothermal field is located within the Hot Springs Mountains, which form part of the western boundary of the Carson Sink. The structure is characterized by east-titled fault blocks and NNE-trending folds. Geologic structure in the area is dominated by high-angle normal faults of varying displacement.

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Resource Cooling	During the last two years the cooling at Brady has leveled off to a rate of 1 degree Fahrenheit per year. The temperature decline at Desert Peak is approximately two degrees Fahrenheit per year.
Sources of Makeup Water	Condensed steam is used for makeup water.
Power Purchaser	Brady power plant — Sierra Pacific Power Company. Desert Peak 2 power plant — Nevada Power Company.
PPA Expiration Date	Brady power plant — 2022. Desert Peak 2 power plant — 2027.
Financing	OFC Senior Secured Notes and ORTP Transaction in the case of the Brady power plant, and OPC Transaction in the case of the Desert Peak 2 power plant.
Don A. Campbell Complex
Location	Mineral County, Nevada
Generating Capacity	41 MW
Number of Power Plants	Two
Technology	The Don A. Campbell power plants utilize an air-cooled binary system.
Subsurface Improvements	9 production wells and five injection wells are connected to the plants.
Material Equipment	Two air-cooled OEC units with the Balance of Plant equipment.
Age	The phase 1 power plant is in its second year of operation and the Phase 2 power plant commenced operation in September 2015.
Land and Mineral Rights	The Don A. Campbell area is comprised of BLM leases.
	Since we the power plants achieved commercial operation, the leases are held by production, as described above in “Description of Our Leases and Lands”. The project’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”.
Resource Information	The Don A. Campbell geothermal reservoir consists of highly fractured, silicified alluvium over at least two square miles. Production and injection are very shallow with five pumped production wells (from depths of 1,350 feet to 1,900 feet) and three injection wells (from depths of 649 feet to 2,477 feet), all targeting northwest-dipping fractures. The thermal fluids are thought to be controlled by a combination of conductive heat transfer from deeper bedrock and through mixing of upwelling thermal fluids from a deeper geothermal system also contained in the bedrock. The system is considered blind with no surface expression of thermal features.
	The temperature of the resource is approximately 259 degrees Fahrenheit.
Resource Cooling	Temperature started declining in mid-2016. We plan to drill a deep injection well to mitigate the decline.
Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted in leases from BLM.
Power Purchaser	Two separate PPAs with SCPPA.
PPA Expiration Date	The phase 1 PPA expires in 2034 and the Phase 2 PPA expires in 2036
Financing	Phase 1 - 4.03% Senior Secured Notes purchased by Munich Re and the cash grant that we received from the U.S. Treasury.
	Phase 2 – Corporate funds and the Opal tax equity transaction.

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Supplemental Information	In April 2015, we closed an equity transaction with Northleaf in which Northleaf acquired a 36.75% equity interest in ORPD. ORPD owns the Puna complex, the Don A. Campbell phase 1 power plant, and the OREG 1, OREG 2, and OREG 3 power plants. See Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “ORPD transaction”. In November 2016, Northleaf purchased a 36.75% equity interest in the Don A. Campbell phase 2 power plant, which was initially added to the existing ORPD portfolio and then contributed to Opal in the tax equity partnership transaction.
Heber Complex
Location	Heber, Imperial County, California
Generating Capacity	92 MW
Number of Power Plants	Five (Heber 1, Heber 2, Heber South, Gould 1 and Gould 2).
Technology	The Heber 1 plant is a dual flash system with a binary bottoming unit called Gould-1 and the Heber 2 group is comprised of the Heber 2, Gould 2 and Heber South plants which all utilize binary systems. The complex uses a water cooled system.
Subsurface Improvements	27 production wells and 38 injection wells connected to the plants through a gathering system.
Major Equipment	17 OEC units and one steam turbine with the Balance of Plant equipment.
Age	The Heber 1 plant commenced commercial operations in 1985 and the Heber 2 plant in 1993. The Gould 1 plant commenced commercial operation in 2006 and the Gould 2 plant in 2005. The Heber South plant commenced commercial operation in 2008.
Land and Mineral Rights	The total Heber area is comprised mainly of private leases. The leases are held by production. The scheduled expiration dates for all of these leases are after the end of the expected useful life of the power plants.
	The complex’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”.
Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases.
Resource Information	The resource supplying the flash flowing Heber 1 wells averages 341 degrees Fahrenheit. The resource supplying the pumped Heber 2 wells averages 316 degrees Fahrenheit.
	Heber production is from deltaic sedimentary sandstones deposited in the subsiding Salton Trough of California’s Imperial Valley. Produced fluids rise from near the magmatic heated basement rocks (18,000 feet) via fault/fracture zones to the near surface. Heber 1 wells produce directly from deep (4,000 to 8,000 feet) fracture zones. Heber 2 wells produce from the nearer surface (2,000 to 4,000 feet) matrix permeability sandstones in the horizontal outflow plume fed by the fractures from below and the surrounding ground waters. Scale deposition in the flashing Heber 1 producers is controlled by down hole chemical inhibition supplemented with occasional mechanical cleanouts and acid treatments. There is no scale deposition in the Heber 2 production wells.

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Resource Cooling	Average cooling of one degree Fahrenheit per year was observed during the past 20 years of production.
Sources of Makeup Water	Water is provided by condensate and by the IID.
Power Purchaser	One PPA with Southern California Edison and two PPAs with SCPPA.
PPA Expiration Date	Heber 1 — 2025, Heber 2 — 2023, and Heber South — 2031. The output from the Gould 1 and Gould 2 power plants is sold under the PPAs with Southern California Edison and SCPPA.
Financing	OrCal Senior Secured Notes and ORTP Transaction.
Jersey Valley Power Plant
Location	Pershing County, Nevada
Generating Capacity	10 MW
Number of Power Plants	One
Technology	The Jersey Valley power plant utilizes an air cooled binary system.
Subsurface Improvements	Two production wells and four injection wells are connected to the plant through a gathering system. The third production well is not connected to the power plant and will be used in the future as required.
Major Equipment	Two OEC units together with the Balance of Plant equipment.
Age	Construction of the power plant was completed at the end of 2010 and the off-taker approved commercial operation status under the PPA effective on August 30, 2011.
Land and Mineral Rights	The Jersey Valley area is comprised of BLM leases. The leases are held by production. The scheduled expiration dates for all of these leases are after the end of the expected useful life of the power plant.
	The power plant’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”.
Access to Property	Direct access to public roads from leased property and access across leased property under surface rights granted in leases from BLM.
Resource Information	The Jersey Valley geothermal reservoir consists of a small high-permeability area surrounded by a large low-permeability area. The high-permeability area has been defined by wells drilled along an interpreted fault trending west-northwest. Static water levels are artesian; two of the wells along the permeable zone have very high productivities, as indicated by Permeability Index (PI) values exceeding 20 gpm/psi. The average temperature of the resource is 313 degrees Fahrenheit.
Resource Cooling	The rate of cooling was four degrees Fahrenheit in 2015 but it has been moderating since we reduced the injection rate in a well near the production wells. To offset the reduction of injection in this well, we diverted more fluid to farther away wells (by increasing injection pressure).
Power Purchaser	Nevada Power Company
PPA Expiration Date	2032
Financing	OFC 2 Senior Secured Notes, corporate funds, ITC cash grant from the U.S. Treasury and the Opal transaction.

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Mammoth Complex
Location	Mammoth Lakes, California
Generating Capacity	29 MW
Number of Power Plants	Three (G-1, G-2, and G-3).
Technology	The Mammoth complex utilizes air cooled binary systems.
Subsurface Improvements	Ten production wells and five injection wells are connected to the plants through a gathering system.
Major Equipment	Two new OECs and six turbo-expanders together with the Balance of Plant equipment.
Age	The G-1 plant commenced commercial operations in 1984 and the G-2 and G-3 power plants commenced commercial operation in 1990. We recently replaced the equipment at the G-1 plant with new OECs.
Land and Mineral Rights	The total Mammoth area is comprised mainly of BLM leases. The leases are held by production. The scheduled expiration dates for all of these leases are after the end of the expected useful life of the power plants.
	The complex’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”.
Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases.
Resource Information	The average resource temperature is 339 degrees Fahrenheit.
	The Casa Diablo/Basalt Canyon geothermal field at Mammoth lies on the southwest edge of the resurgent dome within the Long Valley Caldera. It is believed that the present heat source for the geothermal system is an active magma body underlying the Mammoth Mountain to the northwest of the field. Geothermal waters heated by the magma flow from a deep source (greater than 3,500 feet) along faults and fracture zones from northwest to southeast east into the field area.
	The produced fluid has no scaling potential.
Resource Cooling	In the last three years the temperature has stabilized and there is no notable decline, although one degree Fahrenheit per year was observed during the prior 20 years of production.
Power Purchaser	G1 and G3 plants — PG&E and G2 plant — Southern California Edison.
PPA Expiration Date	G-1 and G-3 plants — 2034 and G-2 plant — 2027.
Financing	OFC Senior Secured Notes and ORTP Transaction.

McGinness Hills Complex
Location	Lander County, Nevada
Generating Capacity	86 MW
Number of Power Plants	Two
Technology	The McGinness Hills complex utilizes an air cooled binary system.
Subsurface Improvements	Ten production wells and six injection wells are connected to the power plant.
Material Equipment	Six air cooled OEC units with the Balance of Plant equipment.

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Age	The first phase commenced commercial operation on July 1, 2012, and the second phase on February 1, 2015.
Land and Mineral Rights	The McGinness Hills area is comprised of private and BLM leases.
	The leases require annual rental payments, as described above in “Description of Our Leases and Lands”.
	The rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”.
Resource Information	The McGinness Hills geothermal reservoir is contained within a network of fractured rocks over an area at least three square miles.  The reservoir is contained in both Tertiary intrusive and Paleozoic sedimentary (basement) rocks.   The thermal fluids within the reservoir are inferred to flow upward through the basement rocks along the NNE-striking faults at several fault intersections.  The thermal fluids then generally outflow laterally to the NNE and SSW along the NNE-striking faults.  No modern thermal manifestations exist at McGinness Hills, although hot spring deposits encompass an area of approximately 0.25 square miles and indicate a history of surface thermal fluid flow.  The resource temperature averages 335 degrees Fahrenheit and the fluids are sourced from the reservoir at elevations between 2,000 to 5,000 feet below the surface.
Resource Cooling	The temperature has been stable since the first phase began operation with no notable cooling.
Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted in leases from BLM.
Power Purchaser	Nevada Power Company
PPA Expiration Date	2033
Financing	OFC 2 Senior Secured Notes, ITC cash grant from the U.S. Treasury for Phase 1 and the Opal transaction
Brawley Complex (formerly known as North Brawley)
Location	Imperial County, California
Generating Capacity	18 MW (See supplemental information below)
Number of Power Plants	One
Technology	The Brawley power plant utilizes a water-cooled binary system.
Subsurface Improvements	36 wells have been drilled and are connected to the plants through its gathering system. As we improved our knowledge of the reservoir, we moved some of the wells between production and injection and left some idle. Currently, we have 13 wells connected to the production header and 23 wells, connected to the injection header.
Major Equipment	Five OEC units together with the Balance of Plant equipment.
Age	The power plant commenced commercial operation on March 31, 2011.
Land and Mineral Rights	The total Brawley area is comprised of private leases. The leases are held by production. The scheduled expiration date for all of these leases is after the end of the expected useful life of the power plant.
	The plant’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”.

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Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases.
Resource Information	Brawley production is from deltaic and marine sedimentary sands and sandstones deposited in the subsiding Salton Trough of the Imperial Valley. Based on seismic refraction surveys the total thickness of these sediments in the Brawley area is over 15,000 feet. The shallow production reservoir (from depths of 1,500 to 4,500 feet) that was developed is fed by fractures and matrix permeability and is conductively heated from the underlying fractured reservoir which convectively circulates magmatically heated fluid. Produced fluid salinity ranges from 20,000 to 50,000 ppm, and the moderate scaling and corrosion potential is chemically inhibited. The temperature of the deeper fractured reservoir fluids exceed 525 degrees Fahrenheit, but the fluid is not yet developed because of severe scaling and corrosion potential. The deep reservoir is not dedicated to the Brawley power plant.
	The average produced fluid resource temperature is 310 degrees Fahrenheit.
Resource Cooling	Temperature depends on the mix of operating production wells that we use.
Sources of Makeup Water	Water is provided by the IID.
Power Purchaser	Southern California Edison
PPA Expiration Date	2031.
Financing	Corporate funds and ITC cash grant from the U.S. Treasury.
Supplemental Information	We are currently selling the power generated by the Brawley complex to Southern California Edison under the existing PPA at a capacity level of approximately 10 MW and we are planning to increase it to 18 MW by the end of 2017. We developed a more robust chemical supply system to our production wells. The problems with the previous system caused premature failures of the production pumps. With the new system, we plan to activate several idle wells and recently drilled well at the area of east Brawley, which will enable us to increase generation.
OREG 1 Power Plant
Location	Four gas compressor stations along the Northern Border natural gas pipeline in North and South Dakota.
Generating Capacity	22 MW
Number of Units	Four
Technology	The OREG 1 power plant utilizes our air cooled OEC units.
Major Equipment	Four WHOH and four OEC units together with the Balance of Plant equipment.
Age	The OREG 1 power plant commenced commercial operations in 2006.
Land	Easement from NBPL.
Access to Property	Direct access to the plant from public roads.
Power Purchaser	Basin Electric Power Cooperative
PPA Expiration Date	2031
Financing	Corporate funds.
Supplemental Information	In April 2015, we closed an equity transaction with Northleaf in which Northleaf acquired a 36.75% equity interest in ORPD. ORPD owns the Puna complex, the Don A. Campbell phase 1 power plant, and the OREG 1, OREG 2, and OREG 3 power plants. See Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “ORPD transaction”.

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OREG 2 Power Plant
Location	Four gas compressor stations along the Northern Border natural gas pipeline; one in Montana, two in North Dakota, and one in Minnesota.
Generating Capacity	22 MW
Number of Units	Four
Technology	The OREG 2 power plant utilizes our air cooled OEC units.
Major Equipment	Four WHOH and four OEC units together with the Balance of Plant equipment.
Age	The OREG 2 power plant commenced commercial operations during 2009.
Land	Easement from NBPL.
Access to Property	Direct access to the plant from public roads.
Power Purchaser	Basin Electric Power Cooperative
PPA Expiration Date	2034
Financing	Corporate funds.
Supplemental Information	In April 2015, we closed an equity transaction with Northleaf in which Northleaf acquired a 36.75% equity interest in ORPD. ORPD owns the Puna complex, the Don A. Campbell phase 1 power plant, and the OREG 1, OREG 2, and OREG 3 power plants. See Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “ORPD transaction”.
OREG 3 Power Plant
Location	A gas compressor station along Northern Border natural gas pipeline in Martin County, Minnesota.
Generating Capacity	5.5 MW
Number of Units	One
Technology	The OREG 3 power plant utilizes our air cooled OEC units.
Major Equipment	One WHOH and one OEC unit along with the Balance of Plant equipment.
Age	The OREG 3 power plant commenced commercial operations during 2010.
Land	Easement from NBPL.
Access to Property	Direct access to the plant from public roads.
Power Purchaser	Great River Energy
PPA Expiration Date	2029
Financing	Corporate funds.
Supplemental Information	In April 2015, we closed an equity transaction with Northleaf in which Northleaf acquired a 36.75% equity interest in ORPD. ORPD owns the Puna complex, the Don A. Campbell phase 1 power plant, and the OREG 1, OREG 2, and OREG 3 power plants. See Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “ORPD transaction”.

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OREG 4 Power Plant
Location	A gas compressor station along natural gas pipeline in Denver, Colorado.
Generating Capacity	3.5 MW
Number of Units	One
Technology	The OREG 4 power plant utilizes our air cooled OEC units.
Major Equipment	Two WHOH and one OEC unit together with the Balance of Plant equipment.
Age	The OREG 4 power plant commenced commercial operations during 2009.
Land	Easement from Trailblazer Pipeline Company.
Access to Property	Direct access to the plant from public roads.
Power Purchaser	Highline Electric Association
PPA Expiration Date	2029
Financing	Corporate funds.
Ormesa Complex
Location	East Mesa, Imperial County, California
Generating Capacity	40 MW
Number of Power Plants	Three (OG I, OG II and GEM 3). The GEM 2 plant was taken off line during 2015 due to plant operation optimization.
Technology	The OG plants utilize a binary system and the GEM plant utilize a flash system. The complex uses a water cooling system.
Subsurface Improvements	24 production wells and 57 injection wells connected to the plants through a gathering system.
Material Major Equipment	8 OEC units and one steam turbines with the Balance of Plant equipment.
Age	The various OG I plants commenced commercial operations between 1987 and 1989, and the OG II plant commenced commercial operation in 1988. Between 2005 and 2007 a significant portion of the old equipment in the OG plants was replaced (including turbines through repowering). The GEM plant commenced commercial operation in 1989, and a new bottoming unit was added in 2007.
Land and Mineral Rights	The total Ormesa area is comprised of BLM leases. The leases are held by production. The scheduled expiration dates for all of these leases are after the end of the expected useful life of the power plants.
	The complex’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”.
Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases.
Resource Information	The average resource temperature is 308 degrees Fahrenheit. Production is from sandstones.
	Productive sandstones are between 1,800 and 6,000 feet, and have only matrix permeability. The currently developed thermal anomaly was created in geologic time by conductive heating and direct outflow from an underlying convective fracture system. Produced fluid salinity ranges from 2,000 ppm to 13,000 ppm, and minor scaling and corrosion potential is chemically inhibited.

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Resource Cooling	In the last year, the temperature has declined by two degrees Fahrenheit.
Sources of Makeup Water	Water is provided by the IID.
Power Purchaser	Southern California Edison under a single PPA.
PPA Expiration Date	November 29, 2017. New PPA was signed with SCPPA as described below.
Financing	OFC Senior Secured Notes and ORTP Transaction.
Supplemental Information	We recently entered into a 25-year PPA with SCPPA that will begin on November 30, 2017. This PPA will supersede the current 30-year SO#4 with Southern California Edison that has a variable energy rate tied primarily to volatile natural gas prices. Under the terms of the new PPA, energy from the power plant will be sold to SCPPA at a rate of $77.25 per megawatt hour with no annual escalation. Contract capacity is 35 MW, with a maximum generation equivalent to a net capacity of about 43 MW.
Puna Complex
Location	Puna district, Big Island, Hawaii
Generating Capacity	38 MW
Number of Power Plants	Two
Technology	The Puna plants utilize our geothermal combined cycle and binary systems. The plants use an air cooled system.
Subsurface Improvements	Six production wells and five injection wells connected to the plants through a gathering system.
Major Equipment	One plant consists of ten OEC units made up of ten binary turbines, ten steam turbines and two bottoming units along with the Balance of Plant equipment. The second plant consists of two OEC units along with Balance of Plant equipment.
Age	The first plant commenced commercial operations in 1993. The second plant was placed in service in 2011 and commenced commercial operation in 2012.
Land and Mineral Rights	The Puna complex is comprised of a private lease. The private lease is between PGV and KLP and it expires in 2046. PGV pays an annual rental payment to KLP, which is adjusted every five years based on the CPI.
	The state of Hawaii owns all mineral rights (including geothermal resources) in the state. The state has issued a Geothermal Resources Mining Lease to KLP, and KLP in turn has entered into a sublease agreement with PGV, with the state’s consent. Under this arrangement, the state receives royalties of approximately three percent of the gross revenues.
Access to Property	Direct access to the leased property is readily available via county public roads located adjacent to the leased property. The public roads are at the north and south boundaries of the leased property.
Resource Information	The geothermal reservoir at Puna is located in volcanic rock along the axis of the Kilauea Lower East Rift Zone. Permeability and productivity are controlled by rift-parallel subsurface fissures created by volcanic activity. They may also be influenced by lens-shaped bodies of pillow basalt which have been postulated to exist along the axis of the rift at depths below 7,000 feet.
	The distribution of reservoir temperatures is strongly influenced by the configuration of subsurface fissures and temperatures are among the hottest of any geothermal field in the world, with maximum measured temperatures consistently above 650 degrees Fahrenheit.

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Resource Cooling	The resource temperature is stable.
Power Purchaser	Three PPAs with HELCO (see “Supplemental Information” below).
PPA Expiration Date	2027
Financing	Operating Lease and ITC cash grant from the U.S. Treasury. Also, in April 2015, we closed an equity transaction with Northleaf in which Northleaf acquired a 36.75% equity interest in ORPD. ORPD owns the Puna complex, the Don A. Campbell phase 1 power plant, and the OREG 1, OREG 2, and OREG 3 power plants. Discussed in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “ORPD transaction”.
Supplemental Information	The pricing for the energy that is sold from the Puna complex is as follows:
	•  For the first on-peak 25 MW, the energy is still based on HELCO's avoided cost.
	•  For the next on-peak 5 MW, the energy price has changed from a diesel-based price to a flat rate of 11.8 cents per kWh, escalating by 1.5% per year.
	•  For the new on-peak 8 MW, the price is 9 cents per kWh for up to 30,000 MWh/year and 6 cents per kWh above 30,000 MWh/year, escalating by 1.5% per year. We recently signed an agreement for the period between February 1, 2017 and December 31, 2017 that waives the 30,000 kWh threshold requirements such as the price for energy delivered during on-peak hours shale be 6 cents per kWh regardless of the amount of MWh delivered.
	•  For the first off-peak 22 MW the energy price has not changed from avoided cost.
	The off-peak energy above 22 MW is dispatchable:
	1.  For the first off-peak 5 MW, the price has changed from a diesel-based price to a flat rate of 11.8 cents per kWh, escalating by 1.5% per year.
	2.  For the energy above 27 MW (up to 38 MW), the price is 6 cents per kWh, escalating by 1.5% per year.
	The capacity payment for the first 30 MW remains the same ($160 kW/year for the first 25 MW and $100.95 kW/year for the additional 5 MW). For the new 8 MW power plant the annual capacity payment is $2 million.
Steamboat Complex
Location	Steamboat, Washoe County, Nevada
Generating Capacity	73 MW
Number of Power Plants	Six (Steamboat 2 and 3, Burdette (Galena 1), Steamboat Hills, Galena 2 and Galena 3).
Technology	The Steamboat complex utilizes a binary system (except for Steamboat Hills, which utilizes a single flash system). The complex uses air and water cooling systems.
Subsurface Improvements	24 production wells and 11 injection wells connected to the plants through a gathering system.

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Major Equipment	Nine individual air-cooled and one water-cooled OEC units, and one steam turbine together with the Balance of Plant Equipment.
Age	The power plants commenced commercial operation in 1992, 2005, 2007 and 2008. During 2008, the Rotoflow expanders at Steamboat 2 and 3 were replaced with four turbines manufactured by us.
Land and Mineral Rights	The total Steamboat area is comprised of 41% private leases, 41% BLM leases and 18% private land owned by us. The leases are held by production. The scheduled expiration dates for all of these leases are after the end of the expected useful life of the power plants.
	The complex’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”. We have easements for the transmission lines we use to deliver power to our power purchasers.
Resource Information	The resource temperature at the lower area averages 272 degrees Fahrenheit. The resource at Steamboat Hills averages 348 degrees Fahrenheit.
	The Steamboat geothermal field is a typical basin and range geothermal reservoir. Large and deep faults that occur in the rocks allow circulation of ground water to depths exceeding 10,000 feet below the surface. Horizontal zones of permeability permit the hot water to flow eastward in an out-flow plume. The Steamboat Hills and Galena 2 power plants produce hot water from fractures associated with normal faults. The rest of the power plants acquire their geothermal water from the horizontal out-flow plume. The water in the Steamboat reservoir has a low total solids concentration. Scaling potential is very low unless the fluid is allowed to flash which will result in calcium carbonate scale. Injection of cooled water for reservoir pressure maintenance prevents flashing.
Resource Cooling	Historically, the resource temperature declined at two degrees Fahrenheit per year, however, since the expansion of the complex, the rate of decline has been approximately five degrees Fahrenheit per year (see “Supplemental Information” below). In 2016, temperature decline moderated to three degrees Fahrenheit in the lower area and four degrees Fahrenheit in Steamboat Hills.
Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases.
Sources of Makeup Water	Water is provided by condensate and the local utility.
Power Purchaser	Sierra Pacific Power Company (for Steamboat 2 and 3, Burdette (Galena1), Steamboat Hills, and Galena 3) and Nevada Power Company (for Galena 2).
PPA Expiration Date	Steamboat 2 and 3 — 2022, Burdette (Galena1) — 2026, Steamboat Hills — 2018, Galena 3 — 2028, and Galena 2 — 2027.
Financing	OFC Senior Secured Notes and ORTP Transaction (Steamboat 2 and 3, and Burdette (Galena1)) and OPC Transaction (Steamboat Hills, Galena 2, and Galena 3)
Supplemental information	In 2016 a new injection well was connected to the power plant and an old injection well that was cooling production was shut down.

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Tuscarora Power Plant
Location	Elko County, Nevada
Projected Generating Capacity	18 MW
Number of Power Plants	One
Technology	The Tuscarora power plant utilizes a water cooled binary system.
Subsurface Improvements	Three production and six injection wells are connected to the power plant. A fourth production well is planned for 2017 and should be in place by mid-year.
Major Equipment	Two water cooled OEC units with the Balance of Plant equipment.
Age	The power plant commenced commercial operation on January 11, 2012.
Land and Mineral Rights	The Tuscarora area is comprised of private and BLM leases.
	The leases are currently held by payment of annual rental payments, as described above in “Description of Our Leases and Lands”. The plant’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”.
Resource Information	The Tuscarora geothermal reservoir consists of an area of approximately 2.5 square miles. The reservoir is contained in both Tertiary and Paleozoic (basement) rocks. The Paleozoic section consists primarily of sedimentary rocks, overlain by tertiary volcanic rocks. Thermal fluid in the native state of the reservoir flows upward and to the north through apparently southward-dipping, basement formations. At an elevation of roughly 2,500 feet with respect to mean sea level, the upwelling thermal fluid enters the tertiary volcanic rocks and flows directly upward, exiting to the surface at Hot Sulphur Springs.
	The average resource temperature is 335 degrees Fahrenheit.
Resource Cooling	We expect gradual decline in the cooling trend from two degrees Fahrenheit per year in the next two to three years, to less than one degree Fahrenheit per year over the long term.
Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted in leases from BLM.
Sources of Makeup Water	Water is provided from five water makeup wells.
Power Purchaser	Nevada Power Company
PPA Expiration Date	2032
Financing	OFC 2 Senior Secured Notes, ITC cash grant from the U.S. Treasury and the OrLeaf transaction.
Supplemental information	Due to the draught years, supply of make-up water for the plant cooling system is declining. With the increase in ambient temperatures, during the summer months we have experienced shortfall at levels that required at certain times reduction in plant generation. In 2016 a new production well was drilled and will be on line in 2017.  Cooling water supply continues to curtail production in the summer.

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Foreign Operating Power Plants

The following descriptions summarize certain industry metrics for our foreign operating power plants:

Amatitlan Power Plant (Guatemala)
Location	Amatitlan, Guatemala
Generating Capacity	20 MW
Number of Power Plants	One
Technology	The Amatitlan power plant utilizes an air cooled binary system and a small back pressure steam turbine (1 MW).
Subsurface Improvements	Five production wells and two injection wells connected to the plants through a gathering system.
Major Equipment	Two OEC units and one steam turbine together with the Balance of Plant equipment.
Age	The plant commenced commercial operation in 2007.
Land and Mineral Rights	Total resource concession area (under usufruct agreement with INDE) is for a term of 25 years from April 2003. Leased and company owned property is approximately three percent of the concession area. Under the agreement with INDE, the power plant company pays royalties of 3.5% of revenues up to 20.5 MW generated and 2% of revenues exceeding 20.5 MW generated.
	The generated electricity is sold at the plant fence. The transmission line is owned by INDE.
Resource Information	The resource temperature is an average of 520 degrees Fahrenheit.
	The Amatitlan geothermal area is located on the north side of the Pacaya Volcano at approximately 5,900 feet above sea level. Hot fluid circulates up from a heat source beneath the volcano, through deep faults to shallower depths, and then cools as it flows horizontally to the north and northwest to hot springs on the southern shore of Lake Amatitlan and the Michatoya River Valley.
Resource Cooling	Approximately two degrees Fahrenheit per year.
Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the lease agreement.
Power Purchasers	INDE and another local purchaser.
PPA Expiration Date	The PPA with INDE expires in 2028.
Financing	Senior secured limited recourse project finance loan from Banco Industrial S.A. and Westrust Bank (International) Limited.
Bouillante power plant (Guadeloupe Island)
Location	Guadeloupe Island, a French territory in the Caribbean
Generating Capacity	15 MW
Number of Power Plants	One
Technology	The Bouillante power plant uses direct steam turbines.
Subsurface Improvements	Two production wells and one injection well connected to the plant through a gathering system.
Major Equipment	One steam turbine together with the Balance of Plant equipment.

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Age	The plant commenced commercial operation in 1996.
Land and Mineral Rights	Geothermal concession of roughly 24 square miles valid through April 30, 2050. Facilities located on land held in fee, as well as long-term leases and easements.
Resource Information	The resource temperature is an average of 485 degrees Fahrenheit. Production comes from a fault that extends from the mountain into the ocean.
Resource Cooling	The resource temperature is stable.
Access to Property	Direct access to site through public roads.
Power Purchaser	EDF.
PPA Expiration Date	15-year PPA until 2031.
Financing	Corporate funds
Supplemental information	The project is owned 80% interest jointly by Ormat and CDC allocated 75% to Ormat and 25% to CDC. Ormat and CDC will gradually increase their combined interest in the project to 85% and Sageos will hold the remaining balance.
Olkaria III Complex (Kenya)
Location	Naivasha, Kenya
Generating Capacity	139 MW
Number of Power Plants	Five (Olkaria III Phase 1 and Olkaria III Phase 2, together Plant 1, Plant 2, Plant 3 and Plant 4).
Technology	The Olkaria III complex utilizes an air cooled binary system.
Subsurface Improvements	18 production wells and five injection wells connected to the plants through a gathering system.
Major Equipment	13 OEC units together with the Balance of Plant equipment.
Age	Plant 4 commenced commercial operation in January 2016, Plant 3 in January 2014 and Plant 2 in April 2013. The first phase of Plant 1 commenced operation in 2000 and the second phase in 2009.
Land and Mineral Rights	The total Olkaria III area is comprised of government leases. A license granted by the Kenyan government provides exclusive rights of use and possession of the relevant geothermal resources for an initial period of 30 years, expiring in 2029, which initial period may be extended for two additional five-year terms. The Kenyan Minister of Energy has the right to terminate or revoke the license in the event work in or under the license area stops during a period of six months, or there is a failure to comply with the terms of the license or the provisions of the law relating to geothermal resources. Royalties are paid to the Kenyan government monthly based on the amount of power supplied to the power purchaser and an annual rent.
	The power generated is purchased at the metering point located immediately after the power transformers in the 220 kV sub-station within the power plant, before the transmission lines, which belong to the utility.
Resource Information	The average resource temperature is 570 degrees Fahrenheit.
	The Olkaria III geothermal field is on the west side of the greater Olkaria geothermal area located at approximately 6,890 feet above sea level within the Rift Valley.

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	Hot geothermal fluids rise up from deep in the northeastern portion of the concession area, penetrating a low permeability zone below 3,280 feet above sea level to a high productivity, two-phase zone identified between 3,280 and 4,270 feet ASL.
Resource Cooling	The resource temperature is stable.
Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the lease agreement.
Power Purchaser	KPLC
PPA Expiration Date	Plan 2 in 2033, Plant 1 in 2034, Plant 3 in 2034 and Plant 4 in 2036
Financing	Senior secured project finance loan from OPIC and a subordinated loans from DEG.
Supplemental information	We are planning to add additional 10 MW that will come on line during 2018.
Zunil Power Plant (Guatemala)
Location	Zunil, Guatemala
Generating Capacity	23 MW (see “Supplemental Information” below for information on current generating capacity)
Number of Power Plants	One
Technology	The Zunil power plant utilizes an air cooled binary system.
Subsurface	Six production wells and two injection wells are connected to the plant through a gathering system.
Major Equipment	Seven OEC units together with the Balance of Plant equipment.
Age	The plant commenced commercial operation in 1999.
Land and Mineral Rights	The land owned by the plant includes the power plant, workshop and open yards for equipment and pipes storage.
	Pipelines for the gathering system transit through a local agricultural area’s right of way acquired by us. The geothermal wells and resource are owned by INDE. Our produced power is sold at our property line; power transmission lines are owned and operated by INDE.
Resource Information	The Zunil geothermal reservoir is hosted in Tertiary volcanic rocks which include overly fractured granodiorite. Production wells produce a reservoir from 536-572 degrees Fahrenheit to a depth of approximately 2,860-4,300 feet. A shallow steam cap exists in the production area of the field, and most of the wells produce high enthalpy fluid due to the presence of two-phase conditions in their feed zones. The wells target northwest- and northeast-trending fractures for permeability. These fractures are also thought to control upwelling from the volcanically-heated source. The upwelling fluids form a steam cap, and fluids and steam reach the surface along fractures, forming springs and fumaroles throughout the geothermal field.
Resource Cooling	The resource temperature is stable.
Access to Property	Direct access to public roads.

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Power Purchaser	INDE
PPA Expiration Date	2034
Supplemental Information	In January 2014, we signed an amendment to the PPA with INDE to extend its term by 15 years until 2034.
	The PPA amendment also transfers operation and management responsibilities of the Zunil geothermal field from INDE to Ormat for the term of the amended PPA in exchange for an increase in tariff. Additionally, INDE exercised its right under the PPA to become a partner in the Zunil power plant and to hold a three percent equity interest. The power plant generates approximately 16 MW due to lack of sufficient geothermal resource supply. We successfully improved the heat supply and gradually increased the generation. We expect that this improvement and the increased tariff will increase the energy portion of revenues.
	According to the PPA amendment, payments for the Zunil plant will be made as follows:
	1. Capacity payment:
	a.  Until 2019, the capacity payment will be calculated based on a 24 MW generating capacity regardless of the actual performance of the power plant.
	b.  From 2019 on, the capacity payment will be based on actual delivered capacity and the capacity rate will be reduced.
	2. Energy payment:
	a.  From January 2014 until 2034, the energy payment will include a geothermal field O&M rate based on actual delivered energy in addition to the energy rate on actual delivered energy.
	b.  From 2019 on, the energy rate on delivered energy will increase and will compensate the reduction in capacity price.

Projects under Construction

Some of our projects are in various stages of construction and include some projects that we have fully released for construction and two projects that are in initial stages of construction.

The following is a description of projects in the U.S., Honduras, Kenya and Indonesia that were released for, and are in different stages of, construction. These projects are expected to have a total generating capacity of 110 MW (representing our interest).

Olkaria III – Plant 1 Repowering (Kenya)
Location	Naivasha, Kenya
Projected Generating Capacity	10MW

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Projected Technology	The power plant will utilize an air cooled binary system.
Condition	Drilling of the first well is pending permit. Construction start is planned for the second quarter of 2017.
Subsurface Improvement	We plan to drill two new production wells.
Land and Mineral Rights	The total Olkaria III area is comprised of government leases. See description above under “Olkaria III Complex”.
Resource Information	The Olkaria III geothermal field is on the west side of the greater Olkaria geothermal area located within the Rift Valley at approximately 6,890 feet above sea level.
	Hot geothermal fluids rise up from deep in the northeastern portion of the concession area through low permeability at a shallow depth to a high productivity two-phase region from 3,280 to 4,270 feet above sea level.
Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the lease agreement.
Power Purchaser	2034.
Financing	Corporate finance.
Projected Operation	First half of 2018.
Supplemental Information	We plan to add additional OEC unit to the existing Olkaria III Plant 1. The generated electricity from the new unit will be sold under Plant 1 PPA.

Platanares

Location	Copan, Honduras
Projected Generating Capacity	35 MW
Projected Technology	The plant will utilize an air cooled binary system.
Condition	Construction ongoing. Production temperature is 354 degrees Fahrenheit with high productivity.
Subsurface Improvement	We have successfully drilled 4 production wells and 2 injection wells.
Land and Mineral Rights	The project is located within a geothermal concession granted by the Department of Energy, Natural Resources, Environment, and Mines (SERNA), and located on fee land owned by GeoPlatanares and on land under lease from various private and public entities. The concession conveys to GeoPlatanares the right to exploit the geothermal resources contained within. The transmission corridor consists of easement agreements between GeoPlatanares and various private and public entities.

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Resource Information	The project is located along a narrow river valley in western Honduras. The field is covered mostly by Miocene volcanic deposits.  Numerous boiling hot springs and fumaroles emit along active faults along an area around two miles in length.  The geothermal reservoir is supported by highly fractured volcanic and metasedimentary rock units. Wells are less than 800 meter deep.
Access to Property	Public roads provide access to the project area. In order to improve access for heavy equipment and large loads, GeoPlatanares has entered into a lease agreement with a private landowner for a small segment of road linking two leased parcels
Power Purchaser	30-year PPA with ENEE, the national utility of Honduras.
Financing	Corporate funds during construction.
Supplemental Information	We hold the assets, including the project’s wells, land, permits and a PPA, under a BOT structure for 15 years from the date of commercial operation. Commercial operation is expected before the end of 2017.
Sarulla (Indonesia)
Location	Tapanuli Utara North Sumatra Namura I Langit area, Indonesia.
Ownership	SOL is a consortium consists of Medco Energi Internasional Tbk, Inpex Corporation, Itochu Corporation, Kyushu Electric Power Co. Inc., and one of our wholly owned subsidiaries that hold 12.75% interest.
Projected Generating Capacity	Three phases with a total of approximately 321 MW (Ormat’s share is approximately 41MW)
Projected Technology	Integrated Geothermal Combined Cycle Unit comprised of 3 back pressure steam turbines and 18 OEC units.
Condition	The first phase with a 110 MW generating capacity is currently under testing and expected to commence operation in March 2017. For the second phase power plant, engineering and procurement has been substantially completed, site construction is in progress and all of the major generating units including those to be supplied by Ormat were delivered. For the third phase, engineering, procurement and construction work at the site are in progress and manufacturing of equipment to be supplied by Ormat is underway as planned. Drilling for the second and third phases is still ongoing and the project has achieved to date, based on preliminary estimates, approximately 80% of the required production capacity and over 85% of the required injection capacity.
Land and Mineral Rights	Most of the land for the project was acquired from private owners with some land leased from governmental agencies.
Resource Information	Two field areas, NIL and SIL host a liquid-dominated system. Previously drilled wells have temperatures from 275°C to 310°C. Flow tests of the first SOL partnership well, N2n-1, predict 22 NMW single well capacity with 751 T/hr total flow and 125 T/hr steam flow at 12.5 bar and 1126 kJ/kg. Both fields are within a tectonic half graven adjacent to the Great Sumatran Fault. In addition to highly encouraging production results, extensive surface manifestations, including fumaroles, boiling hot springs, and alteration, highlight an extensive area of productivity.
Access to Property	Access to property for the project has been secured.
Power Purchaser	30-year Energy Sales Contract with PT PLN (the state electric utility)
Financing	In May 2014, the consortium reached financial closing on $1.17 billion to finance the development of the project with a consortium of lenders comprised of JBIC, the Asian Development Bank and six commercial banks and obtained construction and term loans under a limited recourse financing package backed by political risk guarantee from JBIC.

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Projected Operation	The project will be constructed in three phases with a total of 321 MW, utilizing both steam and brine extracted from the geothermal field to increase the power plant’s efficiency. The first phase of operations is expected to commence commercial operation in March 2017, the second phase is expected to commence operations toward the end of 2017 and commercial operation of the third phase is still expected to commence 18 months after the scheduled commercial operation of the first phase, in 2018.
Supplemental Information	The Sarulla project will be owned and operated by the consortium members under the framework of a JOC and ESC. Under the JOC, PT Pertamina Geothermal Energy, the concession holder for the project, has provided the consortium with the right to use the geothermal field, and under the ESC, PT PLN, the state electric utility, will be the off-taker at Sarulla for a period of 30 years. In addition to our equity holdings in the consortium, we designed the Sarulla plant and will supply our OECs to the power plant. The project has missed a few milestones defined under the loan documents, but has received waivers from the lenders and as of now the project is in compliance with lenders requirements. The project is still experiencing delays in the field development and cost overruns resulting from delays and excess drilling costs. Due to the cost overrun in drilling, the lenders have requested from the sponsors to commit for additional equity. The sponsors have agreed and financing documents were revised to reflect this request. With respect to Ormat’s role as a supplier, all contractual milestones under the supply agreement were achieved.
Tungsten (U.S.)
Location	Churchill County, Nevada
Projected Generating Capacity	24 MW
Projected Technology	The plant will utilize an air cooled binary system.
Condition	Field development of the Tungsten plant is ongoing and site construction has started. Production temperature is 274 degrees Fahrenheit with measured high permeability.
Subsurface Improvement	We have successfully drilled four production wells and three injection wells.
Land and Mineral Rights	The Tungsten area is comprised of BLM land.
Resource Information	The project exploits blind resource (no hot springs or fumaroles) in an area of complex faulting associated with the range front fault on the western side of Edwards Creek Valley. Wells are 1650 to 4500 feet deep.
Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted in leases from BLM.
Power Purchaser	Under negotiation.
Financing	Corporate funds during construction.
Supplemental Information	Commercial operation is expected by the end of 2017.

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The following is a description of projects in California and Nevada with an expected total generating capacity of between 65 MW and 70 MW that are in an initial stage of construction:

Dixie Meadows (U.S.)
Location	Churchill County, Nevada
Projected Generating Capacity	15-20 MW
Projected Technology	The plant will utilize an air cooled binary system.
Condition	Field development of the Dixie Meadows plant is ongoing. Production temperature was 292 degrees Fahrenheit on a short flow test with measured high productivity.
Subsurface Improvement	We have successfully drilled one production well and one other which we are considering whether it will be used for injection or as a production well.
Land and Mineral Rights	The Dixie Meadows area is comprised of BLM and private land.
Resource Information	The resource is located in an area of complex faulting with fumaroles and numerous hot springs associated with faults on the western side of Dixie Valley. The production well is 4758 feet deep.
Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted in leases from BLM.
Power Purchaser	Under negotiation.
Financing	Corporate funds during construction.
Supplemental Information	Commercial operation is expected by the end of 2018.
Carson Lake Project (U.S.)
Location	Churchill County, Nevada
Projected Generating Capacity	20 MW
Projected Technology	The Carson Lake power plant will utilize a binary system.
Condition	Initial stage of construction.
Subsurface Improvements	We drilled one well in 2016 that did not meet the commercial criteria. However, this well provided us with more data on the resource. We are currently evaluating the next development steps for the project..
Land and Mineral Rights	The Carson Lake area is comprised of BLM leases.
	The leases are currently held by the payment of annual rental payments, as described above in “Description of Our Leases and Lands.” Unless steam is produced in commercial quantities, the primary term for these leases will expire commencing August 31, 2016. Ormat is considering extending the terms of the lease. The project’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”.

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Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted in leases from BLM.
Resource Information	The expected average temperature of the resource cannot be estimated as field development has not been completed yet.
Power Purchaser	We have not executed a PPA.
Financing	Corporate funds.
Projected Operation	To be determined.
CD4 Project (Mammoth Complex) (U.S.)
Location	Mammoth Lakes, California
Projected Generating Capacity	30 MW
Projected Technology	The CD4 power plant will utilize an air cooled binary system.
Condition	Initial stage of construction.
Subsurface Improvements	We have completed one production well and one injection well. Continued drilling is subject to receipt of additional permits.
Land and Mineral Rights	The total Mammoth area is comprised mainly of BLM leases, which are held by production and are the subject of a unitization agreement.
Access to Property	Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases.
Resource Information	The expected average temperature of the resource cannot be estimated as field development has not been completed yet.
Power Purchaser	We have not executed a PPA.
Financing	Corporate funds.
Projected Operation	To be determined.
Supplemental Information	As part of the process to secure a transmission line, we are participating in the Southern California Edison Wholesale Distribution Access Tariff Transition Cluster Generator Interconnection Process (WDAT LGIA) to deliver energy into the Southern California Edison system at the Casa Diablo Substation. Southern California Edison completed phase I and phase II cluster studies and the WDAT LGIA is being reviewed while re-evaluation of the system upgrades is being completed due to changes in the participants in the cluster study.

Future Projects

Projects under Various Stages of Development

We also have projects under various stages of development in the U.S., Guadeloupe and Kenya. We expect to continue to explore these and other opportunities for expansion so long as they continue to meet our business objectives and investment criteria.

The following is a description of the projects currently under various stages of development and for which we are able to estimate their expected generating capacity. Upon completion of these projects, the generating capacity of the geothermal projects would approximately 70 MW (representing our interest). However, we prioritize our investments based on their readiness for continued construction and expected economics and therefore we are not planning to invest in all of such projects in 2017.

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McGinness Hills Phase 3 (Nevada)

We are developing the 45 MW McGinness Hills phase 3 project that will be added to the McGinness Hills complex on BLM leases located in Lander County, Nevada. We started the drilling activity and we are in advanced stage of securing a PPA. We expect this project to come online either in 2018 or 2019.

Bouillante power plant (Guadeloupe Island)

We are planning to increase the capacity of the Bouillante project by an additional 5 MW to 10 MW. The power plant currently sells its electricity under a 15-year PPA that was entered into in February 2016 with EDF that allows us to sell up to 14.75MW.

Menengai Project (Kenya)

On November 3, 2014, our majority owned Kenyan subsidiary (the Project Company) owned by Ormat (51%), Symbion Power LLC (24.5%) and Civicon Ltd. (24.5%), signed a 25-year PPA with KPLC and a project implementation and steam supply agreement (PISSA) with GDC for the 35 MW Menengai geothermal project in Kenya.

Under the PISSA agreement, the Project Company will finance, design, construct, install, operate and maintain the 35MW Menengai steam plant on a build-own-operate (BOO) basis for 25 years. GDC, which is wholly owned by the Government of Kenya, will develop the geothermal resource, supply the steam for conversion to electricity and maintain the geothermal field through the term of the agreement. The Project Company expects to start construction upon financial closing.

Future Prospects

We have a substantial land position that is expected to support future development on which we have started or plan to start exploration activity. When deciding whether to continue holding lease rights and/or to pursue exploration activity, we diligently prioritize our prospective investments, taking into account resource and probability assessments in order to make informed decisions about whether a particular project will support commercial operations. As a result, during fiscal year 2016, we discontinued exploration activities at three prospects, including Kula in Hawaii, Aqua Quieta in Nevada and Sollipulli in Chile.

Our current land position is comprised of various leases, concessions and private land for geothermal resources of approximately 294,000 acres in 34 prospects including the following:

Nevada (15)

1.	Alum	Exploration studies in progress;
2.	Baltazor	Exploration studies in progress;
3.	Colado	Exploration studies in progress;
4.	Dixie Comstock	Exploration studies in progress;
5.	Don A. Campbell - Phase 3	Not pursuing at this time;
6.	Edwards Creek	Exploration studies in progress;
7.	Horsehaven (formerly Beowawe)	Exploration studies in progress;
8.	North Valley	Exploration studies in progress;
9.	New York Canyon	Exploration studies in progress;
10.	Pearl Hot Springs	Lease acquired but no further action has been taken yet;
11.	Ruby Valley	Lease acquired but no further action has been taken yet;
12.	Rhodes Marsh	Exploration studies in progress;
13.	South Brady	Exploration studies in progress;
14.	Trinity	Exploration studies in progress; and
15.	Tuscarora – Phase 2	Assessment for future expansion.

California (3)

1.	Glamis	Exploration studies in progress;
2.	Rhyolite Plateau	Exploration studies in progress; and
3.	Truckhaven	Exploration studies in progress;

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Oregon (3)

1.	Crump Geyser	Completed exploration studies. Started exploration drilling
2.	Glass Buttes - Midnight Point	Completed exploration studies. Started exploration drilling
3.	Lakeview/ Goose Lake	Completed exploration studies. Started exploration drilling

New Mexico (1)

1. Rincon Completed exploration studies. Started exploration drilling

Utah (2)

1.	Pavant	Exploration studies in progress;
2.	Roosevelt Hot Springs	Exploration studies in progress;

Guatemala (2)

1.	Amatitlan Phase II	Exploration studies in progress; and
2.	Tecumburu	Waiting for additional land acquisition.

Guadeloupe (1)

1. Boiullante Exploration studies in progress

New Zealand (1)

1. Tikitere Signed BOT agreement; exploratory drilling is pending resource consent acceptance.

Indonesia (1)

1. Ungaran Exploration studies in progress

Honduras (1)

1. San Ignacio (12 Tribes) Exploration studies in progress;

Ethiopia (4)

1.	Boku	Under exploration studies;
2.	Dofan	Under exploration studies;
3.	Dugumo Fango	Under exploration studies; and
4.	Shashamane	Under exploration studies.

We also have an option to enter into a geothermal lease in Oregon covering approximately 44,000 acres under a lease option agreement with Weyerhaeuser Company. We are currently exploring the following prospects:

1. Winema Under exploration studies.

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Operations of our Product Segment

Power Units for Geothermal Power Plants. We design, manufacture, and sell power units for geothermal electricity generation, which we refer to as OECs. Our customers include contractors and geothermal plant owners and operators.

The power units are usually paid for in installments, in accordance with milestones set in the supply agreement. Sometimes we agree to provide the purchaser with spare parts (or alternatively, with a non-exclusive license to manufacture such parts). We provide the purchaser with at least a 12-month warranty for such products. We usually also provide the purchaser (often, upon receipt of advances made by the purchaser) with a guarantee, which expires in part upon delivery of the equipment to the site and fully expires at the termination of the warranty period. The guarantees are typically supported by letters of credit.

Power Units for Recovered Energy-Based Power Generation. We design, manufacture, and sell power units used to generate electricity from recovered energy or so-called “waste heat”. Our existing and target customers include interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators, and other companies engaged in other energy-intensive industrial processes. We have two different business models for this product line.

●   The first business model, which is similar to the model utilized in our geothermal power generation business, consists of the development, construction, ownership, and operation of recovered energy-based generation power plants. In this case, we will enter into agreements to purchase industrial waste heat, and enter into long-term PPAs with off-takers to sell the electricity generated by the REG unit that utilizes such industrial waste heat. The power purchasers in such cases generally are investor-owned electric utilities or local electrical cooperatives. This is the business model for our OREG 1, 2, 3 and 4 power plants.

●   Pursuant to the second business model, we construct and sell the power units for recovered energy-based power generation to third parties for use in “inside-the-fence” installations or otherwise. Our customers include gas processing plant owners and operators, cement plant owners and operators and companies in the process industry.

Remote Power Units and other Generators. We design, manufacture and sell fossil fuel powered turbo-generators with capacities ranging from 200 watts to 5,000 watts, which operate unattended in extreme hot or cold climate conditions. The remote power units supply energy for remote and unmanned installations and along communications lines, and cathodic protection along gas and oil pipelines. Our customers include contractors installing gas pipelines in remote areas. In addition, we manufacture and sell generators, including heavy duty direct current generators, for various other uses. The terms of sale of the turbo-generators are similar to those for the power units we produce for power plants.

EPC of Power Plants. We engineer, procure and construct, as an EPC contractor, geothermal and recovered energy power plants on a turnkey basis, using power units we design and manufacture. Our customers are geothermal power plant owners as well as our target customers for the sale of our recovered-energy based power units described above. Unlike many other companies that provide EPC services, we believe we have an advantage in that we are using our own manufactured equipment and thus have better quality and better control over the timing and delivery of required equipment and its related costs. The consideration for such services is usually paid in installments, in accordance with milestones set in the EPC contract and related documents. We usually provide performance guarantees or letters of credit securing our obligations under the contract. Upon delivery of the plant to its owner, such guarantees are replaced with a warranty guarantee, usually for a period ranging from 12 months to 36 months. The EPC contract usually places a cap on our liabilities for failure to meet our obligations thereunder.

In connection with the sale of our power units for geothermal power plants, power units for recovered energy-based power generation, remote power units and other generators, we enter, from time to time, into sales agreements with sales representatives for the marketing and sale of such products pursuant to which we are obligated to pay commissions to such representatives upon the sale of our products in the relevant territory covered by such agreements by such representatives or, in some cases, by other representatives in such territory.

Our manufacturing operations and products are certified ISO 9001, ISO 14001, American Society of Mechanical Engineers, and TÜV, and we are an approved supplier to many electric utilities around the world.

Backlog

We have a product backlog of approximately $251.0 million as of February 27, 2017, which includes revenues for the period between January 1, 2017 and February 27, 2017, compared to $256.3 million as of February 23, 2016, which included revenues for the period between January 1, 2016 and February 23, 2016.

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The following is a breakdown of the Product segment backlog as of February 27, 2017 ($ in millions):

	Expected Completion of the Contract	Sales Expected to be Recognized in 2017		Sales Expected to be Recognized in the years following 2017		Expected Until End of Contract
Geothermal	2018		217.3 - 227.3		21.0 - 31.0		248.3
Recovered Energy	2017		0.4		—		0.4
Remote Power Units	2017		1.6		—		1.6
Other	2017		0.7		—		0.7
Total			220.0 - 230.0		21.0 - 31.0		251.0

Competition

In our Electricity segment, we face competition from geothermal power plant owners and developers as well as other renewable energy providers.

In our Product segment, we face competition from power plant equipment manufacturers or system integrators and from engineering or projects management companies.

As we implement our new strategic plan, we will face competition from a number of sources, many of which may have resources, industry experience, market acceptance or other advantages we do not have. For example, expanding into new technologies, such as energy storage, or markets, such as C&I will involve competition both from companies that already have established businesses in those technologies and markets, other companies seeking to acquire established businesses and other new market entrants like us.

    Electricity Segment

Competition in the Electricity segment is particularly marked in the very early stage of either obtaining the rights to the resource for the development of future projects or acquiring a site already in a more advanced stage of development. Once we or other developers obtained such rights or own a power plant, competition is limited. From time to time and in different jurisdictions competing geothermal developers become our customers in the Product segment.

The main companies competing with us in the geothermal sector in the U.S. are CalEnergy, Calpine Corporation, Terra-Gen Power LLC, Enel Green Power S.p.A and other smaller pure play developers. Outside the U.S., in many cases our competitors are companies that are gaining experience developing geothermal projects in their own countries such as Mercury (formerly Mighty River Power) and Contact Energy in New Zealand, and local developers and steam turbine manufacturers in Indonesia. Some of our competitors are now seeking to take the local experience they have gained and develop geothermal projects in other countries. These competitors include Energy Development Corporation from the Philippines and Enel Green Power from Italy. Some Turkish developers are also focusing on the international market. Additionally, we see competition from small country-specific companies.

In obtaining new PPAs, we also face competition from companies engaged in the power generation business from other renewable energy sources, such as wind power, biomass, solar power and hydro-electric power. In the last few years, competition from the wind and solar power generation industries has increased significantly.

As a geothermal company, we are focused on niche markets where our site-specific and base load advantages can allow us to develop competitive projects.

In the demand response and energy storage markets, VEI competes primarily with specialized demand management providers rather than with the traditional curtailment service providers. VIE differentiate itself from its competotors with its proprietry software and analytical strengths, wider use cases, customer base, business model, market presence and in other aspects of its business.

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The storage space is comprised of many players which are divided into different verticals and sub verticals like OEMs, integrators, battery management systems, energy management systems, battery producers, power conversion systems, DER system design and optimization, micro grids design, monitoring and control and companies that are realizing storage assets' economic value through the optimization of storage assets' operation in real time electricity markets. VEI's proprietary software, analytical operational platform and significant differentiated experience in storage operation and integration with electricity markets, allow VEI to provide multiple value streams (value stacking) from a single storage installation. We expect to continue and grow VEI's business following the completion of the acquisition of VEI's business and assets by our subsidiary Viridity.

  Product Segment

Our competitors among power plant equipment suppliers are divided into high enthalpy and low enthalpy competitors. Our main high enthalpy competitors are industrial steam turbine manufacturers such as Mitsubishi Hitachi Power Systems, Fuji Electric Co., Ltd. and Toshiba of Japan, GE/Nuovo Pignone brand and Ansaldo Energia of Italy. As noted above, we recently signed a strategic collaboration agreement with one of these competitors, Toshiba Corporation.

Our low enthalpy competitors are binary systems manufacturers using the Organic Rankine Cycle such as Fuji Electric Co., Ltd of Japan, Atlas Copco Company, Exergy of Italy, and Mitsubishi Hitachi Power Systems (which acquired Turboden). While we believe that we have a distinct competitive advantage based on our accumulated experience and current worldwide share of installed binary generation capacity (which is approximately 85%), an increase in competition, which we are currently experiencing, has started to impact our ability to secure new purchase orders from potential customers. The increased competition led to a reduction in the prices that we are able to charge for our binary equipment, which in turn impacted our profitability.

In the REG business, our competitors are other Organic Rankine Cycle manufacturers (such as GE and Mitsubishi/Turboden), manufactures that use Kalina technology (such as Geothermal Energy Research & Development Co., Ltd in Japan), as well as other manufacturers of conventional steam turbines.

In the remote power unit business, we face competition from Global Thermoelectric, as well as from manufacturers of diesel generator sets and small wind and solar installations with batteries.

Currently, none of our competitors compete with us in both the Electricity and the Product segments.

In the case of proposed EPC projects we also compete with other service suppliers, such as project/engineering companies.

Customers

All of our revenues from the sale of electricity in the year ended December 31, 2016 were derived from fully-contracted energy and/or capacity payments under long-term PPAs with governmental and private utility entities. Southern California Edison, Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy), HELCO, SCPPA and KPLC accounted for 5.1%, 19.2%, 4.4%, 10.2% and 16.5% of total revenues, respectively, for the year ended December 31, 2016.

Based on publicly available information, as of December 31, 2016, the issuer ratings of Southern California Edison, HELCO, Sierra Pacific Power Company, Nevada Power Company, SCPPA, Pacific Gas & Electric and EDF were as set forth below:

Issuer	Standard & Poor’s Ratings Services	Moody’s Investors Service Inc.
Southern California Edison	BBB+ (stable outlook)	A2 (stable outlook)
HELCO	BBB- (stable outlook)	Rating withdrawn
Sierra Pacific Power Company	A (stable outlook)	Baa1 (stable outlook)
Nevada Power Company	A (stable outlook)	Baa1 (stable outlook)
SCPPA	BBB+ (stable outlook)	Aa3 (stable outlook)
Pacific, Gas and Electric	BBB+ (Positive outlook)	A3 (positive outlook)
EDF	A-(stable outlook)	Aa3 (stable outlook)

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The credit ratings of any power purchaser may change from time to time. There is no publicly available information with respect to the credit rating or stability of the power purchasers under the PPAs for our foreign power plants.

Our revenues from the Product segment are derived from contractors or owners or operators of power plants, process companies, and pipelines.

Raw Materials, Suppliers and Subcontractors

In connection with our manufacturing activities, we use raw materials such as steel and aluminum. We do not rely on any one supplier for the raw materials used in our manufacturing activities, as all of these raw materials are readily available from various suppliers.

We use subcontractors for some of the manufacturing of our products components and for construction activities of our power plants, which allows us to expand our construction and development capacity on an as-needed basis. We are not dependent on any one subcontractor and expect to be able to replace any subcontractor, or assume such manufacturing and construction activities of our projects ourselves, without adverse effect to our operations.

Employees

As of December 31, 2016, we employed 1,180 employees, of which 474 were located in the U.S., 566 were located in Israel and 140 were located in other countries. We expect that future growth in the number of our employees will be mainly attributable to the purchase and/or development of new power plants.

As of the date of this report, the only employees that are represented by a labor union are the employees of the recent acquired Bouilluante power plant located in the Guadeloupe Island. The employees in Guadeloupe are represented by the Confédération Générale du Travail de Guadeloupe. We have never experienced any labor dispute, strike or work stoppage. We consider our relations with our employees to be satisfactory. We believe our future success will depend on our continuing ability to hire, integrate, and retain qualified personnel.

In the U.S., we currently do not have employees represented by unions recognized by the Company under collective bargaining agreements. However, a union filed a petition with the NLRB seeking to organize the operations and maintenance employees at the Puna project.  A global settlement was reached in principle in February 2016 and all issues were settled and closed.

We have no collective bargaining agreements with respect to our Israeli employees. However, by order of the Israeli Ministry of Economy and Industry, the provisions of a collective bargaining agreement between the Histadrut (the General Federation of Labor in Israel) and the Coordination Bureau of Economic Organizations (which includes the Industrialists Association) may apply to some of our Israeli non-managerial, finance and administrative, and sales and marketing personnel. This collective bargaining agreement principally concerns cost of living pay increases, length of the workday, minimum wages and insurance for work-related accidents, annual and other vacation, sick pay, and determination of severance pay, pension contributions, and other conditions of employment. We currently provide such employees with benefits and working conditions, which are at least as favorable as the conditions specified in the collective bargaining agreement.

Insurance

We maintain business interruption insurance, casualty insurance, including flood, volcanic eruption, earthquake and cyber coverage, and primary and excess liability insurance, control of wells, construction all risk, as well as customary worker’s compensation and automobile, marine transportation insurance and such other commercial insurance, if any, as is generally carried by companies engaged in similar businesses and owning similar properties in the same general areas or as may be required by any of our PPAs, or any lease, financing arrangement, or other contract. To the extent any such casualty insurance covers both us and/or our power plants, and any other person and/or plants, we generally have specifically designated as applicable solely to us and our power plants “all risk” property insurance coverage in an amount based upon the estimated full replacement value of our power plants (provided that earthquake, volcanic eruption and flood coverage may be subject to annual aggregate limits depending on the type and location of the power plant) and business interruption insurance in an amount that also varies from power plant to power plant.

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We generally purchase insurance policies to cover our exposure to certain political risks involved in operating in developing countries. Political risk insurance policies are generally issued by entities which specialize in such policies, such as MIGA (a member of the World Bank Group), or by private sector providers, such as Lloyd Syndicates, Zurich Emerging Markets and other such companies. To date, all of our political risk insurance contracts are with the Multilateral Investment Guarantee Agency and with Zurich Emerging Markets. Currently we hold such insurance for our Zunil and Olkaria operating power plants, and for the Sarulla project, which is under construction. Such insurance policies generally cover, subject to the limitations and restrictions contained therein, losses derived from a specified governmental act, such as confiscation, expropriation, riots, and the inability to convert local currency into hard currency and, in certain cases, the breach of agreements with governmental entities, up to approximately 90% of our net equity investment.

Regulation of the Electric Utility Industry in the United States

The following is a summary overview of the electric utility industry and applicable federal and state regulations, and should not be considered a full statement of the law or all issues pertaining thereto.

PURPA

PURPA provides the owners of power plants certain benefits described below if a power plant is a “Qualifying Facility”. A small power production facility is a Qualifying Facility if: (i) the facility does not exceed 80 MW; (ii) the primary energy source of the facility is biomass, waste, renewable resources, or any combination thereof, and at least 75% of the total energy input of the facility is from these sources, and fossil fuel input is limited to specified uses; and (iii) the facility, if larger than one megawatt, has filed with FERC a notice of self-certification of qualifying status, or has filed with FERC an application for FERC certification of qualifying status that has been granted. The 80 MW size limitation, however, does not apply to a facility if (i) it produces electric energy solely by the use, as a primary energy input, of solar, wind, waste or geothermal resources; and (ii) an application for certification or a notice of self-certification of qualifying status of the facility was submitted to FERC prior to December 21, 1994, and construction of the facility commenced prior to December 31, 1999.

FERC's regulations under PURPA exempt owners of small power production Qualifying Facilities that use geothermal resources as their primary source and other Qualifying Facilities that are 30 MW or under in size from regulation under the PUHCA 2005, from many provisions of the FPA and from state laws relating to the financial, organization and rate regulation of electric utilities.

With respect to the FPA, FERC's regulations under PURPA do not exempt from the rate provisions of the FPA sales of energy or capacity from Qualifying Facilities larger than 20 MW in size that are made (a) pursuant to a contract executed after March 17, 2006 that is not a contract made pursuant to a state regulatory authority’s implementation of PURPA or (b) not pursuant to another provision of a state regulatory authority’s implementation of PURPA. The practical effect of these regulations is to require owners of Qualifying Facilities that are larger than 20 MW in size to obtain market-based rate authority from FERC if they seek to sell energy or capacity other than pursuant to a contract executed before March 17, 2006 pursuant to a state regulatory authority’s implementation of PURPA or pursuant to a provision of a state regulatory authority’s implementation of PURPA. Until that contract expires, is terminated or is materially modified, a Qualifying Facility, under a PURPA contract executed prior to March 17, 2006, will not be required to file for authorization to charge for market based rates.

In addition, PURPA and FERC’s regulations under PURPA require that electric utilities offer to purchase electricity generated by Qualifying Facilities at a rate based on the purchasing utility’s incremental cost of purchasing or producing energy (also known as “avoided cost”). However, FERC's regulations under PURPA also allow FERC, upon request of a utility, to terminate a utility’s obligation to purchase energy from Qualifying Facilities upon a finding that Qualifying Facilities have nondiscriminatory access to either: (i) independently administered, auction-based day ahead, and real time markets for energy and wholesale markets for long-term sales of capacity; (ii) transmission and interconnection services provided by a FERC-approved regional transmission entity and administered under an open-access transmission tariff that affords nondiscriminatory treatment to all customers, and competitive wholesale markets that provide a meaningful opportunity to sell capacity and energy, including long and short term sales; or (iii) wholesale markets for the sale of capacity and energy that are at a minimum of comparable competitive quality as markets described in (i) and (ii) above. FERC regulations protect a Qualifying Facility’s rights under any contract or obligation involving purchases or sales that are entered into before FERC has determined that the contracting utility is entitled to relief from the mandatory purchase obligation. FERC has granted the request of California investor-owned utilities for a waiver of the mandatory purchase obligation for Qualifying Facilities larger than 20 MW in size, and is currently re-evaluating the 20 MW threshold for such waiver as well as other aspects of its PURPA regulations.

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We expect that our power plants in the U.S will continue to meet all of the criteria required for Qualifying Facilities under PURPA. However, since the Heber power plants have PPAs with Southern California Edison that require Qualifying Facility status to be maintained, maintaining Qualifying Facility status remains a key obligation. If any of the Heber power plants loses its Qualifying Facility status our operations could be adversely affected. Loss of Qualifying Facility status would eliminate the Heber power plants’ exemption from the FPA and thus, among other things, the rates charged by the Heber power plants in the PPAs with Southern California Edison and SCPPA would become subject to FERC regulation. Further, it is possible that the utilities that purchase power from the power plants could successfully obtain a waiver of the mandatory-purchase obligation in their service territories. For example, the three California investor-owned utilities have received such a waiver from FERC for projects larger than 20 MW. If this occurs or if FERC reduces the 20 MW threshold or eliminates the mandatory purchase obligation, the power plants’ existing PPAs will not be affected, but the utilities will not be obligated under PURPA to renew or extend these PPAs or execute new PPAs upon the existing PPAs’ expiration, if the size is above the waiver threshold.

  PUHCA

Under PUHCA 2005, the books and records of a utility holding company, its affiliates, associate companies, and subsidiaries are subject to FERC and state commission review with respect to transactions that are subject to the jurisdiction of either FERC or the state commission or costs incurred by a jurisdictional utility in the same holding company system. However, if a company is a utility holding company solely with respect to Qualifying Facilities, exempt wholesale generators, or foreign utility companies, it will not be subject to review of books and records by FERC under PUHCA 2005. Qualifying Facilities or exempt wholesale generators that make only wholesale sales of electricity are not subject to state commissions’ rate regulations and, therefore, in all likelihood would not be subject to any review of their books and records by state commissions pursuant to PUHCA 2005 as long as the Qualifying Facility is not part of a holding company system that includes a utility subject to regulation in that state.

 FPA

Pursuant to the FPA, FERC has exclusive jurisdiction over the rates for most wholesale sales of electricity and transmission in interstate commerce. These rates may be based on a cost of service approach or may be determined on a market basis through competitive bidding or negotiation. FERC's regulations under PURPA exempt owners of small power production Qualifying Facilities that use geothermal resources as their primary source and other Qualifying Facilities that are 30 MW or under in size from many provisions of the FPA. If any of the power plants were to lose its Qualifying Facility status, such power plant could become subject to the full scope of the FPA and applicable state regulations. The application of the FPA and other applicable state regulations to the power plants could require our power plants to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility. Even if a power plant does not lose Qualifying Facility status, if a PPA with a power plant expires, is terminated or is materially modified, the owner of a Qualifying Facility power plant in excess of 20 MW will become subject to rate regulation under the Federal Power Act.

If a power plant in the U.S. were to become subject to FERC’s ratemaking jurisdiction under the FPA as a result of loss of Qualifying Facility status and the PPA remains in effect, FERC may determine that the rates currently set forth in the PPA are not just and reasonable and may set rates that are lower than the rates currently charged. In addition, FERC may require that the power plant refund a portion of amounts previously paid by the relevant power purchaser to such power plant. Such events would likely result in a decrease in our future revenues or in an obligation to disgorge revenues previously earned by from the power plant, either of which would have an adverse effect on our revenues.

Moreover, the loss of the Qualifying Facility status of any of our power plants selling energy to Southern California Edison could also permit Southern California Edison, pursuant to the terms of its PPA, to cease taking and paying for electricity from the relevant power plant and to seek refunds for past amounts paid and/or a reduction in future payments. In addition, the loss of any such status would result in the occurrence of an event of default under the indenture for the OFC Senior Secured Notes and the OrCal Senior Secured Notes and hence would give the indenture trustee the right to exercise remedies pursuant to the indenture and the other financing documents.

 State Regulation

Our power plants in California and Nevada, by virtue of being Qualifying Facilities that make only wholesale sales of electricity, are not subject to rate, financial and organizational regulations applicable to electric utilities in those states. The power plants each sell or will sell their electrical output under PPAs to electric utilities (Sierra Pacific Power Company, Nevada Power Company, Southern California Edison or SCPPA). All of the utilities except SCPPA are regulated by their respective state public utilities commissions. Sierra Pacific Power Company and Nevada Power Company, which merged and are doing business as NV Energy, are regulated by the PUCN. Southern California Edison is regulated by the CPUC.

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Under Hawaii law, non-fossil generators are not subject to regulation as public utilities. Hawaii law provides that a geothermal power producer is to negotiate the rate for its output with the public utility purchaser. If such rate cannot be determined by mutual accord, the PUCH will set a just and reasonable rate. If a non-fossil generator in Hawaii is a Qualifying Facility, federal law applies to such Qualifying Facility and the utility is required to purchase the energy and capacity at its avoided cost. The rates for our power plant in Hawaii are established under a long-term PPA with HELCO.

Environmental Permits

U.S. environmental permitting regimes with respect to geothermal projects center upon several general areas of focus. The first involves land use approvals. These may take the form of Special Use Permits or Conditional Use Permits from local planning authorities or a series of development and utilization plan approvals and right of way approvals where the geothermal facility is entirely or partly on BLM or U.S. Forest Service lands. Certain federal approvals require a review of environmental impacts in conformance with the federal National Environmental Policy Act. In California, some local permit approvals require a similar review of environmental impacts under a state statute known as the California Environmental Quality Act. These federal and local land use approvals typically impose conditions and restrictions on the construction, scope and operation of geothermal projects.

The second category of permitting focuses on the installation and use of the geothermal wells themselves. Geothermal projects typically have three types of wells: (i) exploration wells designed to define and verify the geothermal resource, (ii) production wells to extract the hot geothermal liquids (also known as brine) for the power plant, and (iii) injection wells to inject the brine back into the subsurface resource. For example, in Nevada and on BLM lands, the well permits take the form of geothermal drilling permits for well installation. Approvals are also required to modify wells, including for use as production or injection wells. For all wells drilled in Nevada, a geothermal drilling permit must be obtained from the Nevada Division of Minerals. Those wells in Nevada to be used for injection will also require Underground Injection Control permits from the Nevada Division of Environmental Protection. Geothermal wells on private lands in California require drilling permits from the California Department of Conservation’s DOGGR. The eventual designation of these installed wells as individual production or injection wells and the ultimate closure of any wells is also reviewed and approved by DOGGR pursuant to a DOGGR-approved Geothermal Injection Program.

A third category of permits involves the regulation of potential air emissions associated with the construction and operation of wells and power plants and surface water discharges associated with construction and operations activities. Generally, each well and plant requires a preconstruction air permit and storm water discharge permit before earthwork can commence. In addition, in some jurisdictions the wells that are to be used for production require and those used for injection may require air emissions permits to operate. Internal combustion engines and other air pollutant emissions sources at the projects may also require air emissions permits. For our projects, these permits are typically issued at the state or county level. Permits are also required to manage storm water during project construction and to manage drilling muds from well construction, as well as to manage certain discharges to surface impoundments, if any.

A fourth category of permits, that are required in both California and Nevada, includes ministerial permits such as building permits, hazardous materials storage and management permits, and pressure vessel operating permits. We are also required to obtain water rights permits in Nevada. In addition to permits, there are various regulatory plans and programs that are required, including risk management plans (federal and state programs) and hazardous materials management plans (in California).

In some cases our projects may also require permits, issued by the applicable federal agencies or authorized state agencies, regarding threatened or endangered species, permits to impact wetlands or other waters and notices of construction of structures which may have an impact on airspace. Environmental laws and regulations may change in the future, which may lead to increases in the time to receive such permits and associated costs of compliance.

As of the date of this report, all of the material environmental permits and approvals currently required for our operating power plants have been obtained. We are currently experiencing regulatory delays in obtaining various environmental permits and approvals required for projects in development and construction. These delays may lead to increases in the time and cost to complete these projects. Our operations are designed and conducted to comply with applicable environmental permit and approval requirements. Non-compliance with any such requirements could result in fines and penalties, and could also affect our ability to operate the affected project.

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Environmental Laws and Regulations

Our facilities and operations are subject to a number of environmental laws and regulations relating to development, construction and operation. In the U.S, these may include the Clean Air Act, the Clean Water Act, the Emergency Planning and Community Right-to-Know Act, the Endangered Species Act, the National Environmental Policy Act, the Resource Conservation and Recovery Act, and related state laws and regulations.

Our geothermal operations involve significant quantities of brine (substantially, all of which we reinject into the subsurface) and scale, both of which can contain materials (such as arsenic, antimony, lead, and naturally occurring radioactive materials) in concentrations that exceed regulatory limits used to define hazardous waste. We also use various substances, including isopentane and industrial lubricants that could become potential contaminants and are generally flammable. Hazardous materials are also used in our equipment manufacturing operations in Israel. As a result, our projects are subject to domestic and foreign federal, state and local statutory and regulatory requirements regarding the use, storage, fugitive emissions, and disposal of hazardous substances. The cost of investigation and removal or remediation activities associated with a spill or release of such materials could be significant.

Although we are not aware of any mismanagement of these materials, including any mismanagement prior to the acquisition of some of our power plants, that has materially impaired any of the power plant sites, any disposal or release of these materials onto the power plant sites, other than by means of permitted injection wells, could lead to contamination of the environment and result in material cleanup requirements or other responsive obligations under applicable environmental laws. We believe that at one time there may have been a gas station located on the Mammoth complex site, but because of significant surface disturbance and construction since that time further physical evaluation of the environmental condition of the former gas station site has been impractical. We believe that, given the subsequent surface disturbance and construction activity in the vicinity of the suspected location of the service station, it is likely that environmental contamination, if any, associated with the former facilities and any associated underground storage tanks would have already been encountered if they still existed.

Regulation Related to New Activity

Our recent entry into the energy storage space and planned provision of energy management, demand response and load shedding services require us to obtain and maintain certain additional authorizations and approvals.  These include (1) authorization from FERC to make wholesale sales of power, capacity, and ancillary services at market-based rates, and (2) membership status with eligibility to serve designated contractual functions in the RTOs of PJM PJM, the NYISO, and the ERCOT.   In the future, we may need to obtain and maintain similar membership and eligibility status with other RTOs in order to offer such services in their respective areas.

Regulation of the Electric Utility Industry in our Foreign Countries of Operation

The following is a summary overview of certain aspects of the electric industry in the foreign countries in which we have an operating geothermal power plant. As such, it should not be considered a full statement of the laws in such countries or all of the issues pertaining thereto.

Guatemala. The General Electricity Law of 1996, Decree 93-96, created a wholesale electricity market in Guatemala and established a new regulatory framework for the electricity sector. The law created a new regulatory commission, the CNEE, and a new wholesale power market administrator, the AMM, for the regulation and administration of the sector. The AMM is a private not-for-profit entity. The CNEE functions as an independent agency under the Ministry of Energy and Mines and is in charge of regulating, supervising, and controlling compliance with the electricity law, overseeing the market and setting rates for transmission services, and distribution to medium and small customers. All distribution companies must supply electricity to such customers pursuant to long-term contracts with electricity generators. Large customers can contract directly with the distribution companies, electricity generators or power marketers, or buy energy in the spot market. Guatemala has approved a Law of Incentives for the Development of Renewable Energy Power plants, Decree 52-2003, in order to promote the development of renewable energy power plants in Guatemala. This law provides certain benefits to companies utilizing renewable energy, including a 10-year exemption from corporate income tax and VAT on imports and customs duties. On September 16, 2008, CNEE issued a resolution which approved the Technical Norms for the Connection, Operation, Control and Commercialization of the Renewable Distributed Generation and Self-producers Users with Exceeding Amounts of Energy. This Technical Norm was created to regulate all aspects of generation, connection, operation, control and commercialization of electric energy produced with renewable sources to promote and facilitate the installation of new generation plants, and to promote the connection of existing generation plants which have exceeding amounts of electric energy for commercialization. It is applicable to projects with a capacity of up to 5 MW.

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Kenya. The electric power sector in Kenya is regulated by the Kenyan Energy Act.  Among other things, the Kenyan Energy Act provides for the licensing of electricity power producers and public electricity suppliers or distributors. KPLC is the only licensed public electricity supplier and has a monopoly in the distribution of electricity in the country. The Kenyan Energy Act permits IPPs to install power generators and sell electricity to KPLC, which is owned by various private and government entities, and which currently purchases energy and capacity from other IPPs in addition to our Olkaria III complex. The electricity sector is regulated by the ERC which was created under the Kenyan Energy Act. KPLC’s retail electricity rates are subject to approval by the ERC. The ERC has an expanded mandate to regulate not just the electric power sector but the entire energy sector in Kenya. Transmission of electricity is now undertaken by KETRACO while another company, GDC, is responsible for geothermal assessment, drilling of wells and sale of steam for electricity operations to IPPs and KenGen.  Both KETRACO and GDC are wholly owned by the government of Kenya.  Under the new national constitution enacted in August 2010, formulation of energy policy (including electricity) and energy regulation are functions of the national government. However, the constitution lists the planning and development of electricity and energy regulation as a function of the county governments (i.e. the regional or local level where an individual power plant is or is intended to be located).

Indonesia. The 2009 Electricity Law divided the power business into two broad categories: (1) the activities supply electrical power (both public supply and captive supply (own use) such as electrical power generation, electrical power transmission, electrical power distribution and the sale of electrical power; (2) the activities involved in electrical power support such as service businesses (consulting, construction, installation, operation & maintenance, certification & training, testing etc) and industry businesses (power tools & power equipment supply). The power generation is dominated by PLN (state owned company) which controls around 70% of generating assets in Indonesia. Private sector participation is allowed through IPPs arrangement. IPP appointment is most often through tender although IPPs cab be directly appointed or selected. The law provides PLN with priority rights to conduct its business throughout Indonesia. As the sole owner of transmission and distribution assets, PLN remains the only business entity involved in transmitting and distributing although the Law allows for private participation. While the 2014 Geothermal Law endorses private participation as the Geothermal IPP. The Geothermal IPP appointment is through tender held by Central Government. The Central Government also awards the tender winner a Geothermal License, accordingly the Geothermal License holder shall conduct exploration and feasibility study within 5 years plus two times one-year extension, shall do well development and power plant construction and may sell the electricity power into PLN for maximum 30 years. Prior the License expiration, The IPP can propose to extend for another 20 years. To encourage the private participation as a geothermal IPP, the Central Government plans to apply Feed in Tariff in near future.

Guadalupe. EDF is the transmission and distribution utility in Guadeloupe and also operates a significant portion of the island’s fossil energy generation. There are also a number of IPPs in Guadeloupe, primarily producing renewable electricity. The electricity sector in Guadeloupe is regulated by the Commission Regulation of Energy (CRE), which also regulates EDF’s operations in mainland France and its other overseas territories. The electricity sector has some enabling features for renewable energy but also several obstacles. One of the biggest support mechanisms is a French law requiring the utility to purchase power from any interconnected renewable generator. The major obstacle preventing further uptake of renewable electricity generation is the cap on variable generation at 30% of instantaneous system load.

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ITEM 1A. RISK FACTORS

Because of the following factors, as well as other variables affecting our business, operating results or financial condition, past financial performance may not be a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods.

Our financial performance depends on the successful operation of our geothermal power and REG plants, which is subject to various operational risks.

Our financial performance depends on the successful operation of our subsidiaries’ geothermal and REG power plants. In connection with such operations, we derived approximately 65.8% of our total revenues for the year ended December 31, 2016 from the sale of electricity. The cost of operation and maintenance and the operating performance of our subsidiaries’ geothermal power and REG plants may be adversely affected by a variety of factors, including some that are discussed elsewhere in these risk factors and the following:

● regular and unexpected maintenance and replacement expenditures;

● shutdowns due to the breakdown or failure of our equipment or the equipment of the transmission serving utility;

● labor disputes;

● the presence of hazardous materials on our power plant sites;

● continued availability of cooling water supply;

● catastrophic events such as fires, explosions, earthquakes, volcanic activity, landslides, floods, releases of hazardous materials, severe weather storms, or similar occurrences affecting our power plants or any of the power purchasers or other third parties providing services to our power plants; and

● the aging of power plants (which may reduce their availability and increase the cost of their maintenance).

Any of these events could significantly increase the expenses incurred by our power plants or reduce the overall generating capacity of our power plants and could significantly reduce or entirely eliminate the revenues generated by one or more of our power plants, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.

As mentioned above, the aging of our power plants may reduce their availability and increase maintenance costs due to the need to repair or replace our equipment.

Our exploration, development, and operation of geothermal energy resources are subject to geological risks and uncertainties, which may result in decreased performance or increased costs for our power plants.

Our primary business involves the exploration, development, and operation of geothermal energy resources. These activities are subject to uncertainties that, in certain respects, are similar to those typically associated with oil and gas exploration, development, and exploitation, such as dry holes, uncontrolled releases, and pressure and temperature decline. Any of these uncertainties may increase our capital expenditures and our operating costs, or reduce the efficiency of our power plants. We may not find geothermal resources capable of supporting a commercially viable power plant at exploration sites where we have conducted tests, acquired land rights, and drilled test wells, which would adversely affect our development of geothermal power plants. Further, since the commencement of their operations, several of our power plants have experienced geothermal resource cooling uncontrolled flow and/or reservoir pressure decline in the normal course of operations. For example, some of Brady’s production wells have cooled significantly due to breakthrough from injection wells. Because geothermal reservoirs are complex geological structures, we can only estimate their geographic area and sustainable output. The viability of geothermal power plants depends on different factors directly related to the geothermal resource (such as the temperature, pressure, storage capacity, transmissivity, and recharge) as well as operational factors relating to the extraction or reinjection of geothermal fluids. For example, at our North Brawley power plant, instability of the sands and clay in the geothermal resource and variability in the chemical composition of the geothermal fluid have all combined to increase our capital expenditures for the plant, as well as our ongoing operating expenses, and have so far prevented the plant from operation at its intended design capacity. Another example is the Sarulla project, where we are both an equity investor and equipment supplier, which has experienced delays and budget cost overruns in the drilling program. Our geothermal energy power plants may also suffer an unexpected decline in the capacity of their respective geothermal wells and are exposed to a risk of geothermal reservoirs not being sufficient for sustained generation of the electrical power capacity desired over time.

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Another aspect of geothermal operations is the management and stabilization of subsurface impacts caused by fluid injection pressures of production and injection fluids to mitigate subsidence. In the case of the geothermal resource supplying the Heber complex, pressure drawdown in the center of the well field has caused some localized ground subsidence, while pressure in the peripheral areas has caused localized ground inflation. Inflation and subsidence, if not controlled, can adversely affect farming operations and other infrastructure at or near the land surface. Potential costs, which cannot be estimated and may be significant, of failing to stabilize site pressures in the Heber complex area include repair and modification of gravity-based farm irrigation systems and municipal sewer piping and possible repair or replacement of a local road bridge spanning an irrigation canal.

Additionally, active geothermal areas, such as the areas in which our power plants are located, are subject to frequent low-level seismic disturbances, volcanic eruptions and lava flows. Serious seismic disturbances, volcanic eruptions and lava flows are possible and could result in damage to our power plants (or transmission lines used by customers who buy electricity from us) or equipment or degrade the quality of our geothermal resources to such an extent that we could not perform under the PPA for the affected power plant, which in turn could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow. If we suffer a serious seismic disturbance, volcanic eruptions and lava flows, our business interruption and property damage insurance may not be adequate to cover all losses sustained as a result thereof. In addition, insurance coverage may not continue to be available in the future in amounts adequate to insure against such seismic disturbances, volcanic eruptions and lava flows.

Furthermore, absent additional geologic/hydrologic studies, any increase in power generation from our geothermal power plants, failure to reinject the geothermal fluid or improper maintenance of the hydrological balance may affect the operational duration of the geothermal resource and cause it to decline in value over time, and may adversely affect our ability to generate power from the relevant geothermal power plant.

Reduced levels of recovered energy required for the operation of our REG power plants may result in decreased performance of such power plants.

Our REG power plants generate electricity from recovered energy or so-called “waste heat” that is generated as a residual by-product of gas turbine-driven compressor stations and a variety of industrial processes. Any interruption in the supply of the recovered energy source, such as a result of reduced gas flows in the pipelines or reduced level of operation at the compressor stations, or in the output levels of the various industrial processes, may cause an unexpected decline in the capacity and performance of our recovered energy power plants.

Our business development activities may not be successful and our projects under construction may not commence operation as scheduled.

We are in the process of developing and constructing a number of new power plants. Our success in developing a particular project is contingent upon, among other things, negotiation of satisfactory engineering and construction agreements and obtaining PPAs and transmission services agreements, receipt of required governmental permits, obtaining adequate financing, and the timely implementation and satisfactory completion of field development, testing and power plant construction commissioning. We may be unsuccessful in accomplishing any of these matters or doing so on a timely basis. Although we may attempt to minimize the financial risks attributable to the development of a project by securing a favorable PPA and applicable transmission services agreements, obtaining all required governmental permits and approvals and arranging, in certain cases, adequate financing prior to the commencement of construction, the development of a power project may require us to incur significant expenses for preliminary engineering, permitting and legal and other expenses before we can determine whether a project is feasible, economically attractive or capable of being financed.

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Currently, we have geothermal projects and prospects under exploration, development or construction in the U.S., Kenya, Guatemala, Guadeloupe, New Zealand, Honduras, Indonesia and Ethiopia, and we intend to pursue the expansion of some of our existing plants and the development of other new plants. Our completion of these facilities is subject to substantial risks, including:

● inability to secure a PPA;

● inability to secure transmission services agreements;

● inability to secure the required financing;

● cost increases and delays due to unanticipated shortages of adequate resources to execute the project such as equipment, material and labor;

● work stoppages resulting from force majeure event including riots, strikes and whether conditions;

● inability to obtain permits, licenses and other regulatory approvals;

● failure to secure sufficient land positions for the wellfield, power plant and rights of way;

● failure by key contractors and vendors to timely and properly perform, including where we use equipment manufactured by others;

● failure by key suppliers to provide steam for electricity generation, including at the Menengai project in Kenya;

● inability to secure or delays in securing the required transmission line and/or capacity;

● adverse environmental and geological conditions (including inclement weather conditions);

● adverse local business law;and

● our attention to other projects and activities, including those in the solar energy and energy storage sectors.

Any one of these could give rise to delays, cost overruns, the termination of the plant expansion, construction or development or the loss (total or partial) of our interest in the project under development, construction, or expansion.

We rely on power transmission facilities that we do not own or control.

We depend on transmission facilities owned and operated by others to deliver the power we sell from our power plants to our customers. If transmission is disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver power to our customers may be adversely impacted and we may either incur additional costs or forego revenues. In addition, lack of access to new transmission capacity may affect our ability to develop new projects. Existing congestion of transmission capacity, as well as expansion of transmission systems and competition from other developers seeking access to expanded systems, could also affect our performance.

We may be unable to obtain the financing we need to pursue our growth strategy and any future financing we receive may be less favorable to us than our current financing arrangements, either of which may adversely affect our ability to expand our operations.

Most of our geothermal power plants generally have been financed using leveraged financing structures, consisting of non-recourse or limited recourse debt obligations. Each of our projects under development or construction and those projects and businesses we may seek to acquire or construct will require substantial capital investment. Our continued access to capital with acceptable terms is necessary for the success of our growth strategy. Our attempts to obtain future financings may not be successful or on favorable terms.

Market conditions and other factors may not permit future project and acquisition financings on terms similar to those our subsidiaries have previously received. Our ability to arrange for financing on a substantially non-recourse or limited recourse basis, and the costs of such financing, are dependent on numerous factors, including general economic conditions, conditions in the global capital and credit markets, investor confidence, the continued success of current power plants, the credit quality of the power plants being financed, the political situation in the country where the power plant is located, and the continued existence of tax and securities laws which are conducive to raising capital. If we are not able to obtain financing for our power plants on a substantially non-recourse or limited recourse basis, we may have to finance them using recourse capital such as direct equity investments or the incurrence of additional debt by us.

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Also, in the absence of favorable financing options, we may decide not to build new plants or acquire facilities from third parties. Any of these alternatives could have a material adverse effect on our growth prospect.

We may also need additional financing to implement our strategic plan. For example, our cash flow from operations and existing liquidity facilities may not be adequate to finance any acquisitions we may want to pursue or new technologies we may want to develop or acquire. Financing for acquisitions or technology-development activities may not be available on the non-recourse or limited recourse basis we have historically used for our business, or on other terms we find acceptable.

Our use of joint ventures may limit our flexibility with jointly owned investments.

We have sold minority equity interests in four of our consolidated subsidiaries, through which we hold a large number of our domestic geothermal power plants and recovered energy generation plants, to different third parties and we have partners that hold a minority equity interest in our geothermal power plant in Guadeloupe. We may continue in the future to develop and/or acquire and/or hold properties in joint ventures with other entities when circumstances warrant the use of these structures. Ownership of assets in joint ventures is subject to risks that may not be present with other methods of ownership, including:

● we could experience an impasse on certain decisions because we do not have sole decision-making authority, which could require us to expend additional resources on resolving such impasses or potential disputes, including litigation or arbitration;

● our joint venture partners could have investment goals that are not consistent with our investment objectives, including the timing, terms and strategies for any investments in the projects that are owned by the joint ventures, which could affect decisions about future capital expenditures, major operational expenditures and retirement of assets, among other things;

● our ability to transfer our interest in a joint venture to a third party may be restricted and the market for our interest may be limited;

● our joint venture partners may be structured differently than us for tax purposes, and this could impact our ability to fully take advantage of federal tax incentives available for renewable energy projects;

● our joint venture partners might become bankrupt, fail to fund their share of required capital contributions or fail to fulfill their obligations as a joint venture partner, which may require us to infuse our own capital into the venture on behalf of the partner despite other competing uses for such capital; and

● our joint venture partners may have competing interests in our markets and investments in companies that compete directly or indirectly with us that could create conflict of interest issues.

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Our international operations expose us to risks related to the application of foreign laws, taxes, economic conditions, labor supply and relations, political conditions, and policies of foreign governments, any of which may adversely affect our business, financial condition, future results and cash flow.

We have substantial operations outside of the U.S., both in our Electricity segment and our Product segment. Our foreign operations are subject to regulation by various foreign governments and regulatory authorities and are subject to the application of foreign laws. Such foreign laws or regulations may not provide the same type of legal certainty and rights, in connection with our contractual relationships in such countries, as are afforded to our operations in the U.S., which may adversely affect our ability to receive revenues or enforce our rights in connection with our foreign operations. Furthermore, existing laws or regulations may be amended or repealed, and new laws or regulations may be enacted or issued. In addition, the laws and regulations of some countries may limit our ability to hold a majority interest in some of the power plants that we may develop or acquire, thus limiting our ability to control the development, construction and operation of such power plants, or our ability to import our products into such countries. Our foreign operations are also subject to significant political, economic and financial risks, which vary by country, and include:

•     changes in government policies or personnel;

•     changes in general economic conditions;

•     restrictions on currency transfer or convertibility;

•     changes in labor relations;

•     political instability and civil unrest;

•     changes in the local electricity and/or geothermal markets;

•     breach or repudiation of important contractual undertakings by governmental entities; and

•     expropriation and confiscation of assets and facilities.

In particular, in regards to our Electricity segment, in Guatemala the electricity sector was partially privatized, and it is currently unclear whether further privatization will occur in the future. Such developments may affect our Amatitlan and Zunil power plants if, for example, they result in changes to the prevailing tariff regime or in the identity and creditworthiness of our power purchasers. In Kenya, any break-up and potential privatization of KPLC may adversely affect our Olkaria III complex. Although we generally obtain political risk insurance in connection with our foreign power plants, such political risk insurance does not mitigate all of the above-mentioned risks. In addition, insurance proceeds received pursuant to our political risk insurance policies, where applicable, may not be adequate to cover all losses sustained as a result of any covered risks and may at times be pledged in favor of the power plant lenders as collateral. Also, insurance may not be available in the future with the scope of coverage and in amounts of coverage adequate to insure against such risks and disturbances. In regards to our Product segment, since we primarily engage in sales in those markets where there is a geothermal reservoir, any such change might adversely affect geothermal developers in those markets and, subsequently, the ability of such developers to purchase our products. In Turkey, we are involved as a major equipment supplier in a significant number of projects that are currently under construction. Due to the latest failed coup and specifically in early 2017, we see growing obstacles that may affect our future business and operations in the country. These include the devaluation of the Turkish Lira and the slowdown in the economy, together with political uncertainties, all of which are causing the cost of funds to increase. Obtaining project financing packages and bank credit is becoming a financial and administrative challenge and we are consistently monitoring these changes in the economic and political environments.

Any or all of the changes discussed above could materially adversely affect our business, financial condition, future results and cash flow.

Our foreign power plants and foreign manufacturing operations expose us to risks related to fluctuations in currency rates, which may reduce our profits from such power plants and operations.

Risks attributable to fluctuations in currency exchange rates can arise when any of our foreign subsidiaries borrow funds or incur operating or other expenses in one type of currency but receive revenues in another. In such cases, an adverse change in exchange rates can reduce such subsidiary’s ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary or increase such subsidiary’s overall expenses. In addition, the imposition by foreign governments of restrictions on the transfer of foreign currency abroad, or restrictions on the conversion of local currency into foreign currency, would have an adverse effect on the operations of our foreign power plants and foreign manufacturing operations, and may limit or diminish the amount of cash and income that we receive from such foreign power plants and operations.

A significant portion of our electricity revenues is attributed to payments made by power purchasers under PPAs. The failure of any such power purchaser to perform its obligations under the relevant PPA or the loss of a PPA due to a default would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.

A significant portion of our revenues is attributed to our electricity revenues derived from power purchasers under the relevant PPAs. There is a risk that any one or more of the power purchasers may not fulfill their respective payment obligations under their PPAs. If any of the power purchasers fails to meet its payment obligations under its PPAs, it could materially and adversely affect our business, financial condition, future results and cash flow.

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Seasonal variations may cause fluctuations in our cash flows, which may cause the market price of our common stock to fall in certain periods.

Our results of operations are subject to seasonal variations. This is primarily because some of our domestic power plants receive higher capacity payments under the relevant PPAs during the summer months, and due to the generally higher time-of-use energy factor during the summer months. Some of our other power plants may experience reduced generation during warm periods due to the lower heat differential between the geothermal fluid and the ambient surroundings. Such seasonal variations could materially and adversely affect our business, financial condition, future results and cash flow. If our operating results fall below the public’s or analysts’ expectations in some future period or periods, the market price of our common stock will likely fall in such period or periods.

Pursuant to the terms of some of our PPAs with investor-owned electric utilities and publicly-owned electric utilities in states that have renewable portfolio standards, the failure to supply the contracted capacity and energy thereunder may result in the imposition of penalties.

Pursuant to the terms of certain of our PPAs, we may be required to make payments to the relevant power purchaser under certain conditions, such as shortfall in delivery of renewable energy and energy credits, and not meeting certain performance threshold requirements, as defined in the relevant PPA. The amount of payment required is dependent upon the level of shortfall in delivery or performance requirements and is recorded in the period the shortfall occurs. In addition, if we do not meet certain minimum performance requirements, the capacity of the relevant power plant may be permanently reduced. Any or all of these considerations could materially and adversely affect our business, financial condition, future results and cash flow.

The SRAC for our power purchasers may decline, which would reduce our power plant revenues and could materially and adversely affect our business, financial condition, future results and cash flow.

Under a number of the PPAs for our power plants in California, the price that Southern California Edison pays is based upon its SRAC, which are the incremental costs that it would have incurred had it generated the relevant electricity itself or purchased such electricity from others. Under settlement agreements between Southern California Edison and a number of power generators in California that are Qualifying Facilities, including our subsidiaries, the energy price component payable by Southern California Edison was fixed through April 2012, but since then is based on Southern California Edison’s SRAC, as determined by the CPUC. The SRAC may vary substantially on a monthly basis, and are expected to be based primarily on natural gas prices for gas delivered to California as well as other factors. The levels of SRAC prices paid by Southern California Edison may decline following the expiration date of the settlement agreements, which in turn would reduce our power plant revenues derived from Southern California Edison under our PPAs and could materially and adversely affect our business, financial condition, future results and cash flow.

Under the terms of a global settlement approved by CPUC (Global Settlement) SRAC for our Ormesa complex, Heber 2 and Mammoth G2 PPAs are tied to a formula with energy market heat rates. The Global Settlement further provides that after July 1, 2015 if the term of any of the PPAs we have for these power plants expires, would have no obligation to purchase power from any of these plants that has a generating capacity in excess of 20 MW, which would apply to the PPAs for our Ormesa complex (53 MW contract capacity) and Heber 2 power plant (37 MW contract capacity) with Southern California Edison. Our Mammoth G2 plant (10.5 MW contract capacity) will be entitled to a new standard offer PPA, with SRAC pricing and capacity payments as determined from time to time by the CPUC. The joint parties to the Global Settlement agreed that the utilities can go to FERC to obtain a waiver of the mandatory purchase obligation under PURPA for Qualifying Facilities above 20 MW and FERC has granted such waiver for these California utilities.

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If any of our domestic power plants loses its current Qualifying Facility status under PURPA, or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded to Qualifying Facilities, our domestic operations could be adversely affected.

Most of our domestic power plants are Qualifying Facilities pursuant to PURPA, which largely exempts the power plants from the FPA, and certain state and local laws and regulations regarding rates and financial and organizational requirements for electric utilities.

If any of our domestic power plants were to lose its Qualifying Facility status, such power plant could become subject to the full scope of the FPA and applicable state regulation. The application of the FPA and other applicable state regulation to our domestic power plants could require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility.

If a domestic power plant were to lose its Qualifying Facility status, it would become subject to full regulation as a public utility under the FPA, and the rates charged by such power plant pursuant to its PPAs would be subject to the review and approval of FERC. FERC, upon such review, may determine that the rates currently set forth in such PPAs are not appropriate and may set rates that are lower than the rates currently charged. In addition, FERC may require that the affected domestic power plant refund amounts previously paid by the relevant power purchaser to such power plant. Even if a power plant does not lose its Qualifying Facility status, pursuant to regulations issued by FERC for Qualifying Facility power plants above 20 MW, if a power plant’s PPA is terminated or otherwise expires, and the subsequent sales are not made pursuant to a state’s implementation of PURPA, that power plant will become subject to FERC’s ratemaking jurisdiction under the FPA. Moreover, a loss of Qualifying Facility status also could permit the power purchaser, pursuant to the terms of the particular PPA, to cease taking and paying for electricity from the relevant power plant or, consistent with FERC precedent, to seek refunds of past amounts paid. This could cause the loss of some or all of our revenues payable pursuant to the related PPAs, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our power plants. If a power purchaser were to cease taking and paying for electricity or seek to obtain refunds of past amounts paid, there can be no assurance that the costs incurred in connection with the power plant could be recovered through sales to other purchasers or that we would have sufficient funds to make such payments. In addition, the loss of Qualifying Facility status would be an event of default under the financing arrangements currently in place for some of our power plants, which would enable the lenders to exercise their remedies and enforce the liens on the relevant power plant.

Pursuant to the Energy Policy Act of 2005, FERC also has the authority to prospectively lift the mandatory obligation of a utility under PURPA to offer to purchase the electricity from a Qualifying Facility if the utility operates in a workably competitive market. Our existing PPAs between a Qualifying Facility and a utility are not affected. If, in addition to the California utilities’ waiver of the mandatory purchase obligation for QF projects that exceed 20 MW described in the risk factor above entitled "The SRAC for our power purchasers may decline, which would reduce our power plant revenues and could materially and adversely affect our business, financial condition, future results and cash flow", the utilities in the other regions in which our domestic power plants operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from the power plant in the region under Federal law upon termination of the existing PPA or with respect to new power plants, which could materially and adversely affect our business, financial condition, future results and cash flow. Moreover, FERC has the authority to modify its regulations relating to the utility’s mandatory purchase obligation under PURPA, which could result in the reduction in the purchase obligation of California and other utilities to a level below 20 MW, or the elimination of the purchase obligation. If that were to occur it could materially and adversely affect our business, financial condition, future results and cash flow.

The reduction or elimination of government incentives could adversely affect our business, financial condition, future results and cash flows.

Construction and operation of our geothermal power plants and recovered energy-based power plants has benefited, and may benefit in the future, from public policies and government incentives that support renewable energy and enhance the economic feasibility of these projects in regions and countries where we operate. Such policies and incentives include PTCs and ITCs, accelerated depreciation tax benefits, renewable portfolio standards, carbon trading mechanisms, rebates, and mandated feed-in-tariffs, and may include similar or other incentives to end users, distributors, system integrators and manufacturers of geothermal, solar and other power products. Some of these measures have been implemented at the federal level, while others have been implemented by different states within the U.S. or countries outside the U.S. where we operate.

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The availability and continuation of these public policies and government incentives have a significant effect on the economics and viability of our development program and continued construction of new geothermal, recovered energy-based, Solar PV power plants and, recently, energy storage projects. Any changes to such public policies, or any reduction in or elimination or expiration of such government incentives could affect us in different ways. For example, any reduction in, termination or expiration of renewable portfolio standards may result in less demand for generation from our geothermal and recovered energy-based, power plants. Any reductions in, termination or expiration of other government incentives could reduce the economic viability of, and cause us to reduce, the construction of new geothermal, recovered energy-based, Solar PV or any other power plants. Similarly, any such changes that affect the geothermal energy industry in a manner that is different from other sources of renewable energy, such as wind or solar, may put us at a competitive disadvantage compared to businesses engaged in the development, construction and operation of renewable power projects using such other resources. Any of the foregoing outcomes could have a material adverse effect on our business, financial condition, future results, and cash flows.

Our financial performance could be adversely affected by changes in the legal and regulatory environment affecting our power plants.

All of our power plants are subject to extensive regulation, and therefore changes in applicable laws or regulations, or interpretations of those laws and regulations, could result in increased compliance costs, the need for additional capital expenditures or the reduction of certain benefits currently available to our power plants. The structure of domestic and foreign federal, state and local energy regulation currently is, and may continue to be, subject to challenges, modifications, the imposition of additional regulatory requirements, and restructuring proposals. We or our power purchasers may not be able to obtain all regulatory approvals that may be required in the future, or any necessary modifications to existing regulatory approvals, or maintain all required regulatory approvals. In addition, the cost of operation and maintenance and the operating performance of geothermal power plants may be adversely affected by changes in certain laws and regulations, including tax laws.

Any changes to applicable laws and regulations could significantly increase the regulatory-related compliance and other expenses incurred by the power plants and could significantly reduce or entirely eliminate the revenues generated by one or more of the power plants, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.

The costs of compliance with environmental laws and of obtaining and maintaining environmental permits and governmental approvals required for construction and/or operation may increase in the future and these costs (as well as any fines or penalties that may be imposed upon us in the event of any non-compliance with such laws or regulations) could materially and adversely affect our business, financial condition, future results and cash flow.

 Environmental laws, ordinances and regulations affecting us can be subject to change and such change could result in increased compliance costs, the need for additional capital expenditures, or otherwise adversely affect us. In addition, our power plants are required to comply with numerous domestic and foreign, federal, regional, state and local statutory and regulatory environmental standards and to maintain numerous environmental permits and governmental approvals required for construction and/or operation. We may not be able to renew, maintain or obtain all environmental permits and governmental approvals required for the continued operation or further development of the power plants. We have not yet obtained certain permits and government approvals required for the completion and successful operation of power plants under construction or enhancement. Our failure to renew, maintain or obtain required permits or governmental approvals, including the permits and approvals necessary for operating power plants under construction or enhancement, could cause our operations to be limited or suspended. Finally, some of the environmental permits and governmental approvals that have been issued to the power plants contain conditions and restrictions, including restrictions or limits on emissions and discharges of pollutants and contaminants, or may have limited terms. If we fail to satisfy these conditions or comply with these restrictions, or with any statutory or regulatory environmental standards, we may become subject to regulatory enforcement action and the operation of the power plants could be adversely affected or be subject to fines, penalties or additional costs.

We could be exposed to significant liability for violations of hazardous substances laws because of the use or presence of such substances at our power plants.

Our power plants are subject to numerous domestic and foreign federal, regional, state and local statutory and regulatory standards relating to the use, storage and disposal of hazardous substances. We use butane, pentane, industrial lubricants, and other substances at our power plants which are or could become classified as hazardous substances. If any hazardous substances are found to have been released into the environment at or by the power plants in concentrations that exceed regulatory limits, we could become liable for the investigation and removal of those substances, regardless of their source and time of release. If we fail to comply with these laws, ordinances or regulations (or any change thereto), we could be subject to civil or criminal liability, the imposition of liens or fines, and large expenditures to bring the power plants into compliance. Furthermore, in the U.S., we can be held liable for the cleanup of releases of hazardous substances at other locations where we arranged for disposal of those substances, even if we did not cause the release at that location. The cost of any remediation activities in connection with a spill or other release of such substances could be significant.

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We believe that at one time there may have been a gas station located on the Mammoth complex site, but because of significant surface disturbance and construction since that time, further physical evaluation of the environmental condition of the former gas station site has been impractical. There may be soil or groundwater contamination and related potential liabilities of which we are unaware related to this site, which may be significant and could materially and adversely affect our business, financial condition, future results and cash flow.

We may decide not to implement, or may not be successful in implementing, one or more elements of our multi-year strategic plan, and the plan as implemented may not achieve its goal to enhance shareholder value through long-term growth of the Company

We adopted a multi-year strategic plan to:

● Expand our geographical base;

● Expand into new technologies, such as energy storage and solar PV electric power generation both in large “utility scale” projects and smaller C&I projects for commercial, industrial, governmental, educational and other institutional customers; and

● Expand our customer base.

There are uncertainties and risks associated with the plan, both as to implementation and outcome. Implementation of the plan may be affected by a number of factors, including that:

● we are still developing some elements of the plan and evaluating how and when some elements of the plan will be implemented,

● we may decide to change, or not implement, one or more elements of the plan over time, and

● we may not be successful in implementing one or more elements of the plan, in each case for a number of reasons.

For example, we will face significant challenges and risks expanding into new technologies (or expanding our geographical or customer base for those new technologies), including:

● Our ability to compete with the large number of other companies pursuing similar business opportunities in energy storage and solar PV power generation, many of which already have established businesses in these areas and/or have greater financial, strategic, technological or other resources than we have.

● Our ability to obtain financing on terms we consider acceptable, or at all, which we may need, for example, to obtain any technology, personnel, intellectual property, or to acquire one or more existing businesses as a platform for our expansion, or to fund internal research and development, for energy storage and solar PV electric power generation products and services.

● Our ability to provide energy storage or solar electric power generation products or services that keep pace with rapidly changing technology, customer preferences, equipment costs, market conditions and other factors that will impact these markets.

● Our ability to devote the amount of management time and other resources required to implement this plan, consistent with continuing to grow our core geothermal and recovered energy businesses; and

● Our ability to recruit appropriate employees

Expanding our geothermal and recovered energy businesses to new customers and geographical areas will have many of the same risks and uncertainties as those outlined above. These or other factors could mean that we decide to change or even abandon, or are otherwise unable to implement, one or more elements of the plan.

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Implementing the plan will involve various costs, including, among other things:

● opportunity costs associated with foregone alternative uses of our resources;

● various expense items that will impact our current financial results; and

● perhaps asset revaluations, for example, businesses or other assets acquired for new energy storage or solar PV power generation products or services suffer impairment charges, as a result of rapidly changing technology, market conditions or otherwise.

These costs may not be recovered, in whole or in part, if one or more elements of the plan are not successfully implemented. These costs, or the failure to implement successfully one or more elements of the plan, could adversely affect the reputation of our group of companies and could materially and adversely affect our business, financial condition, future results and cash flow and the price at which our common stock is traded.

Apart from the risks associated with implementing the plan, the plan itself will expose us to other risks and uncertainties once implemented. For example, expanding our customer base may expose us to different credit profile customers than our current customers. Another example, expanding our geographic base will subject us to risks associated with doing business in new foreign countries in which we will have to learn the business and political environment, and expanding into new technologies will expose us to risks associated with those products and services. Some of these risks may be similar to those we now face, as described in other risks factors; others may differ or be unknown to us now. The success of the plan, once implemented, will depend, among other things, on our ability to manage these risks effectively.

The trading price of our common stock could decline if securities, industry analysts or our investors disagree with our strategic plan or the way we implement it, either as a result of the factors outlined above or for other reasons.

Accordingly, there is no assurance that the plan will enhance shareholder value through long-term growth of the Company to the extent currently anticipated by our management or at all.

We may not be able to successfully integrate companies, which we acquired and may acquire in the future, which could materially and adversely affect our business, financial condition, future results and cash flow.

Our strategy is to continue to expand in the future, including through acquisitions. Integrating acquisitions is often costly, and we may not be able to successfully integrate our acquired companies with our existing operations without substantial costs, delays or other adverse operational or financial consequences. Integrating our acquired companies involves a number of risks that could materially and adversely affect our business, including:

● failure of the acquired companies to achieve the results we expect;

● inability to retain key personnel of the acquired companies;

● risks associated with unanticipated events or liabilities; and

● the difficulty of establishing and maintaining uniform standards, controls, procedures and policies, including accounting controls and procedures.

If any of our acquired companies suffers customer dissatisfaction or performance problems, this could adversely affect the reputation of our group of companies and could materially and adversely affect our business, financial condition, future results and cash flow.

The power generation industry is characterized by intense competition, and we encounter competition from electric utilities, other power producers, and power marketers that could materially and adversely affect our business, financial condition, future results and cash flow.

The power generation industry is characterized by intense competition from electric utilities, other power producers and power marketers. In recent years, there has been increasing competition in the sale of electricity, in part due to excess capacity in a number of U.S. markets and an emphasis on short-term or “spot” markets, and competition has contributed to a reduction in electricity prices. For the most part, we expect that power purchasers interested in long-term arrangements will engage in “competitive bid” solicitations to satisfy new capacity demands. This competition could adversely affect our ability to obtain PPAs and the price paid for electricity by the relevant power purchasers. There is also increasing competition between electric utilities. This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity, and increasing competition in the future will put further pressure on power purchasers to reduce the prices at which they purchase electricity from us.

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We face competition from other companies engaged in the solar, demand response and energy storage sectors and we expect to face competition from other companies in the demand response sector.

The solar power market is intensely competitive and rapidly evolving. We compete with many companies that have longer operating histories in this sector, larger customer bases, and greater brand recognition, as well as, in some cases, significantly greater financial and marketing resources than us. In some cases, these competitors are vertically integrated in the solar energy sector, manufacturing Solar PV, silicon wafers, and other related products for the solar industry, which may give them an advantage in developing, constructing, owning and operating solar power projects. Our limited experience in the Solar PV sector may affect our ability to successfully develop, construct, finance, and operate Solar PV power projects.

VEI, from which we expect to acquire substantially all of its assets and business and which operates in the demand response and energy storage sectors, is not currently experiencing intensive competition due to its position in what is now a niche industry. However, it is known that, as both demand response and energy storage markets grow, Ormat is likely to face increased competition that we expect will arrive from utilities, independent entities, new start-ups, and third party investors. It is critical for us to continue to grow the business market share, and grow our customer base. We plan to continue acquiring related businesses if required to enhance our competitive position.

The existence of a prolonged force majeure event or a forced outage affecting a power plant or the transmission system of the IID could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow.

The operation of our subsidiaries’ geothermal power plants is subject to a variety of risks discussed elsewhere in these risk factors, including events such as fires, explosions, earthquakes, landslides, floods, severe storms, volcanic eruptions, lava flow or other similar events. If a power plant experiences an occurrence resulting in a force majeure event, although our subsidiary that owns that power plant would be excused from its obligations under the relevant PPA the relevant power purchaser may not be required to make any capacity and/or energy payments with respect to the affected power plant or plant so long as the force majeure event continues and, pursuant to certain of our PPAs, will have the right to prematurely terminate the PPA. Additionally, to the extent that a forced outage has occurred, the relevant power purchaser may not be required to make any capacity and/or energy payments to the affected power plant, and if as a result the power plant fails to attain certain performance requirements under certain of our PPAs, the purchaser may have the right to permanently reduce the contract capacity (and correspondingly, the amount of capacity payments due pursuant to such agreements in the future), seek refunds of certain past capacity payments, and/or prematurely terminate the PPA. As a consequence, we may not receive any net revenues from the affected power plant other than the proceeds from any business interruption insurance that applies to the force majeure event or forced outage after the relevant waiting period, and may incur significant liabilities in respect of past amounts required to be refunded.

In addition, if the transmission system of the IID experiences a force majeure event or a forced outage which prevents it from transmitting the electricity from the Heber complex, the Ormesa complex or the North Brawley power plant to the relevant power purchaser, the relevant power purchaser would not be required to make energy payments for such non-delivered electricity and may not be required to make any capacity payments with respect to the affected power plant so long as such force majeure event or forced outage continues. The impact of such force majeure would depend on the duration thereof, with longer outages resulting in greater loss of revenues. In the event of any such force majeure event, our business, financial condition, future results and cash flows could be materially and adversely affected.

Some of our leases will terminate if we do not extract geothermal resources in “commercial quantities”, thus requiring us to enter into new leases or secure rights to alternate geothermal resources, none of which may be available on terms as favorable to us as any such terminated lease, if at all.

Most of our geothermal resource leases are for a fixed primary term, and then continue for so long as geothermal resources are extracted in “commercial quantities” or pursuant to other terms of extension. The land covered by some of our leases is undeveloped and has not yet produced geothermal resources in commercial quantities. Leases that cover land which remains undeveloped and does not produce, or does not continue to produce, geothermal resources in commercial quantities and leases that we allow to expire, will terminate. In the event that a lease is terminated and we determine that we will need that lease once the applicable power plant is operating, we would need to enter into one or more new leases with the owner(s) of the premises that are the subject of the terminated lease(s) in order to develop geothermal resources from, or inject geothermal resources into, such premises or secure rights to alternate geothermal resources or lands suitable for injection. We may not be able to do this or may not be able to do so without incurring increased costs, which could materially and adversely affect our business, financial condition, future results and cash flow.

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Our BLM leases may be terminated if we fail to comply with any of the provisions of the Geothermal Steam Act or if we fail to comply with the terms or stipulations of such leases, which could materially and adversely affect our business, financial condition, future results and cash flow.

Pursuant to the terms of our BLM leases, we are required to conduct our operations on BLM-leased land in a workmanlike manner and in accordance with all applicable laws and BLM directives and to take all mitigating actions required by the BLM to protect the surface of and the environment surrounding the relevant land. Additionally, certain BLM leases contain additional requirements, some of which relate to the mitigation or avoidance of disturbance of any antiquities, cultural values or threatened or endangered plants or animals. In the event of a default under any BLM lease, or the failure to comply with such requirements, or any non-compliance with any of the provisions of the Geothermal Steam Act or regulations issued thereunder, the BLM may, 30 days after notice of default is provided to our relevant project subsidiary, suspend our operations until the requested action is taken or terminate the lease, either of which could materially and adversely affect our business, financial condition, future results and cash flow.

Some of our leases (or subleases) could terminate if the lessor (or sublessor) under any such lease (or sublease) defaults on any debt secured by the relevant property, thus terminating our rights to access the underlying geothermal resources at that location.

The fee interest in the land which is the subject of some of our leases (or subleases) may currently be or may become subject to encumbrances securing loans from third-party lenders to the lessor (or sublessor). Our rights as lessee (or sublessee) under such leases (or subleases) are or may be subject and subordinate to the rights of any such lender. Accordingly, a default by the lessor (or sublessor) under any such loan could result in a foreclosure on the underlying fee interest in the property and thereby terminate our leasehold interest and result in the shutdown of the power plant located on the relevant property and/or terminate our right of access to the underlying geothermal resources required for our operations.

In addition, a default by a sublessor under its lease with the owner of the property that is the subject of our sublease could result in the termination of such lease and thereby terminate our sublease interest and our right to access the underlying geothermal resources required for our operations.

Current and future urbanizing activities and related residential, commercial, and industrial developments may encroach on or limit geothermal or Solar PV activities in the areas of our power plants, thereby affecting our ability to utilize access, inject and/or transport geothermal resources on or underneath the affected surface areas.

Current and future urbanizing activities and related residential, commercial and industrial development may encroach on or limit geothermal activities in the areas of our power plants or construction and operation of Solar PV facilities, thereby affecting our ability to utilize, access, inject, and/or transport geothermal resources on or underneath the affected surface areas or build Solar PV facilities, which require large areas of relatively flat land. In particular, the Heber power plants rely on an area, which we refer to as the Heber Known Geothermal Resource Area, or Heber KGRA, for the geothermal resource necessary to generate electricity at the Heber power plants. Imperial County has adopted a “specific plan area” that covers the Heber KGRA, which we refer to as the “Heber Specific Plan Area”. The Heber Specific Plan Area allows commercial, residential, industrial and other employment oriented development in a mixed-use orientation, which currently includes geothermal uses. Several of the landowners from whom we hold geothermal leases have expressed an interest in developing their land for residential, commercial, industrial or other surface uses in accordance with the parameters of the Heber Specific Plan Area. Currently, Imperial County’s Heber Specific Plan Area is coordinated with the cities of El Centro and Calexico. There has been ongoing underlying interest since the early 1990s to incorporate the community of Heber. While any incorporation process would likely take several years, if Heber were to be incorporated, the City of Heber could replace Imperial County as the governing land use authority, which, depending on its policies, could have a significant effect on land use and availability of geothermal resources.

Current and future development proposals within Imperial County and the City of Calexico, applications for annexations to the City of Calexico, and plans to expand public infrastructure may affect surface areas within the Heber KGRA, thereby limiting our ability to utilize, access, inject and/or transport the geothermal resource on or underneath the affected surface area that is necessary for the operation of our Heber power plants, which could adversely affect our operations and reduce our revenues.

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Current construction works and urban developments in the vicinity of our Steamboat complex of power plants in Nevada may also affect future permitting for geothermal operations relating to those power plants. Such works and developments include plans for the construction of a new casino hotel and other commercial or industrial developments on land in the vicinity of our Steamboat complex.

We depend on key personnel for the success of our business.

In general, our success depends to a significant extent on the performance of our senior management, particularly the continued service of our key employees. Our success also depends on our ability to identify, hire and retain other qualified and experienced key personnel. Although to date we have been successful in identifying, hiring and retaining the services of senior management, we face risks associated with our ability to locate or employ on acceptable terms qualified replacements for our senior management or key employees if their services were no longer available, and with the inherent difficulties and uncertainties of transitioning the Company under the leadership of new management.

In the demand response industry, there is a relatively small pool of experienced personnel. In the relatively new energy storage market, there is an even smaller pool of experienced personnel. Our plans to grow the business we acquire from VEI are dependent on our ability to attract and retain highly specialized demand response and energy storage personnel.

Our inability to successfully identify, hire and retain any key employee could materially harm our business, financial condition, future results and cash flow.

Our power plants have generally been financed through a combination of our corporate funds and limited or non-recourse project finance debt and lease financing. If our project subsidiaries default on their obligations under such limited or non-recourse debt or lease financing, we may be required to make certain payments to the relevant debt holders, and if the collateral supporting such leveraged financing structures is foreclosed upon we may lose certain of our power plants.

Our power plants have generally been financed using a combination of our corporate funds and limited or non-recourse project finance debt or lease financing. Limited recourse project finance debt refers to our additional agreement, as part of the financing of a power plant, to provide limited financial support for the power plant subsidiary in the form of limited guarantees, indemnities, capital contributions and agreements to pay certain debt service deficiencies. Non-recourse project finance debt or lease financing refers to financing arrangements that are repaid solely from the power plant’s revenues and are secured by the power plant’s physical assets, major contracts, cash accounts and, in many cases, our ownership interest in the project subsidiary. If our project subsidiaries default on their obligations under the relevant debt documents, creditors of a limited recourse project financing will have direct recourse to us, to the extent of our limited recourse obligations, which may require us to use distributions received by us from other power plants, as well as other sources of cash available to us, in order to satisfy such obligations. In addition, if our project subsidiaries default on their obligations under the relevant debt documents (or a default under such debt documents arises as a result of a cross-default to the debt documents of some of our other power plants) and the creditors foreclose on the relevant collateral, we may lose our ownership interest in the relevant project subsidiary or our project subsidiary owning the power plant would only retain an interest in the physical assets, if any, remaining after all debts and obligations were paid in full.

Changes in costs and technology may significantly impact our business by making our power plants and products less competitive.

A basic premise of our business model is that generating baseload power at geothermal power plants achieves economies of scale and produces electricity at a competitive price. However, traditional coal-fired systems and gas-fired systems may under certain economic conditions produce electricity at lower average prices than our geothermal plants. In addition, there are other technologies that can produce electricity, most notably fossil fuel power systems, hydroelectric systems, fuel cells, microturbines, windmills, Solar PV cells and Solar PV systems. Some of these alternative technologies currently produce electricity at a higher average price than our geothermal plants, however research and development activities are ongoing to seek improvements in such alternate technologies and their cost of producing electricity is gradually declining. It is possible that advances will further reduce the cost of alternate methods of power generation to a level that is equal to or below that of most geothermal power generation technologies. If this were to happen, the competitive advantage of our power plants may be significantly impaired.

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Our expectations regarding the market potential for the development of recovered energy-based power generation may not materialize, and as a result we may not derive any significant revenues from this line of business.

Demand for our recovered energy-based power generation units may not materialize or grow at the levels that we expect. We currently face competition in this market from manufacturers of conventional steam turbines and may face competition from other related technologies in the future. If this market does not materialize at the levels that we expect, we will not generate any material revenues.

Our intellectual property rights may not be adequate to protect our business.

Our existing intellectual property rights and those we will own following the closing of the Viridity transaction, may not be adequate to protect our business. While we occasionally file patent applications, patents may not be issued on the basis of such applications or, if patents are issued, they may not be sufficiently broad to protect our technology. In addition, any patents issued to us or for which we have use rights may be challenged, invalidated or circumvented.

In order to safeguard our unpatented proprietary know-how, trade secrets and technology, we rely primarily upon trade secret protection and non-disclosure provisions in agreements with employees and others having access to confidential information. These measures may not adequately protect us from disclosure or misappropriation of our proprietary information.

Even if we adequately protect our intellectual property rights, litigation may be necessary to enforce these rights, which could result in substantial costs to us and a substantial diversion of management attention. Also, while we have attempted to ensure that our technology and the operation of our business do not infringe other parties’ patents and proprietary rights, our competitors or other parties may assert that certain aspects of our business or technology may be covered by patents held by them. Infringement or other intellectual property claims, regardless of merit or ultimate outcome, can be expensive and time-consuming and can divert management’s attention from our core business.

Threats of terrorism and catastrophic events that could result from terrorism, cyber-attacks, or individuals and/or groups attempting to disrupt our business, or the businesses of third parties, may impact our operations in unpredictable ways and could adversely affect our business, financial condition, future results and cash flow.

We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber-attacks, including, among others, malware, viruses and attachments to e-mails, and other disruptive activities of individuals or groups. Our generation and transmission facilities, information technology systems and other infrastructure facilities, systems and physical assets, and following the closing of the transaction with VEI, the VPower^TM software, could be directly or indirectly affected by such activities. Terrorist acts or other similar events could harm our business by limiting our ability to generate or transmit power and by delaying the development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure our assets, and could adversely affect operations by contributing to the disruption of supplies and markets for geothermal and recovered energy. Such events could also impair our ability to raise capital by contributing to financial instability and lower economic activity.

We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite our implementation of security measures, all of our technology systems (and any programs or data stored thereon or therein) are vulnerable to security breaches, failures, data leakage or unauthorized access due to such activities. Those breaches and events may result from acts of our employees, contractors or third parties. If our technology systems were to fail or be breached and we were unable to recover in a timely way, we would be unable to fulfill critical business functions, and sensitive confidential and other data could be compromised, which could adversely affect our business, financial condition, future results and cash flow.

The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs. These types of events could adversely affect our business, financial condition, future results and cash flow. In addition such events could require significant management attention and resources and could adversely affect our reputation among customers and the public.

A disruption of transmission or the transmission infrastructure facilities of third parties could negatively impact our business. Because generation and transmission systems are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the impact of an event on the interconnected system within our systems or within a neighboring system. Any such disruption could adversely affect our business, financial condition, future results and cash flow.

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Possible fluctuations in the cost of construction, raw materials, commodities and drilling may materially and adversely affect our business, financial condition, future results, and cash flow.

Our manufacturing operations are dependent on the supply of various raw materials, including primarily steel and aluminum, commodities and industrial equipment components that we use. We currently obtain all such raw materials, commodities and equipment at prevailing market prices. We are not dependent on any one supplier and do not have any long-term agreements with any of our suppliers. Future cost increases of such raw materials, commodities and equipment, to the extent not otherwise passed along to our customers, could adversely affect our profit margins.

Conditions in and around Israel, where the majority of our senior management and our main production and manufacturing facilities are located, may adversely affect our operations and may limit our ability to produce and sell our products or manage our power plants.

The majority of our senior management and our main production and manufacturing facilities are located in Israel. As such, political, economic and security conditions in Israel directly affect our operations.

Since the establishment of the State of Israel in 1948, a number of armed conflicts have taken place between Israel and its Arab neighbors, and the continued state of hostility, varying in degree and intensity, has led to security and economic problems for Israel.

Negotiations between Israel and representatives of the Palestinian Authority in an effort to resolve the state of conflict have been sporadic and have failed to result in peace. The establishment in 2006 of a government in the Gaza territory by representatives of the Hamas militant group has created additional unrest and uncertainty in the region. In each of December 2008, November 2012 and July 2014, Israel engaged in an armed conflict with Hamas, each of which involved additional missile strikes from the Gaza Strip into Israel and disrupted most day-to-day civilian activity in the proximity of the border with the Gaza Strip. Our production facilities in Israel are located approximately 26 miles from the border with the Gaza Strip.

The political instability and civil unrest in the Middle East and North Africa (including the ongoing civil war in Syria) as well as the increased tension between Iran and Israel have raised new concerns regarding security in the region and the potential for armed conflict or other hostilities involving Israel. We could be adversely affected by any such hostilities, the interruption or curtailment of trade between Israel and its trading partners, or a significant downturn in the economic or financial condition of Israel. In addition, the sale of products manufactured in Israel may be adversely affected in certain countries by restrictive laws, policies or practices directed toward Israel or companies having operations in Israel.

In addition, some of our employees in Israel are subject to being called upon to perform military service in Israel, and their absence may have an adverse effect upon our operations. Generally, unless exempt, male adult citizens of Israel under the age of 41 are obligated to perform up to 36 days of military reserve duty annually. Additionally, all such citizens are subject to being called to active duty at any time under emergency circumstances.

These events and conditions could disrupt our operations in Israel, which could materially harm our business, financial condition, future results, and cash flow.

We are a holding company and our revenues depend substantially on the performance of our subsidiaries and the power plants they operate, most of which are subject to restrictions and taxation on dividends and distributions.

We are a holding company whose primary assets are our ownership of the equity interests in our subsidiaries. We conduct no other business and, as a result, we depend entirely upon our subsidiaries’ earnings and cash flow.

The agreements pursuant to which most of our subsidiaries have incurred debt restrict the ability of these subsidiaries to pay dividends, make distributions or otherwise transfer funds to us prior to the satisfaction of other obligations, including the payment of operating expenses, debt service and replenishment or maintenance of cash reserves. In the case of some of our power plants that are owned jointly with other partners, there may be certain additional restrictions on dividend distributions pursuant to our agreements with those partners. Further, if we elect to receive distributions of earnings from our foreign operations, we may incur U.S. taxes on account of such distributions, net of any available foreign tax credits. In all of the foreign countries where our existing power plants are located, dividend payments to us are also subject to withholding taxes. Each of the events described above may reduce or eliminate the aggregate amount of revenues we can receive from our subsidiaries.

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The Israeli Tax Ruling we obtained in connection with our acquisition of Ormat Industries imposes conditions that may limit our flexibility in operating our business and our ability to enter into certain corporate transactions.

The Israel Tax Ruling we obtained in connection with the acquisition of Ormat Industries imposes a number of conditions that limit our flexibility in operating our business and in engaging in certain corporate transactions. Until the end of 2018, we agreed to maintain (and, to the extent that our operations expand, likewise expand) the production activities we currently carry out in Israel. Under certain circumstances, these conditions may not allow us the flexibility that we need to operate our business and may prevent us from taking advantage of strategic opportunities that would benefit our business and our stockholders.

As a result of the share exchange, a substantial percentage of our shares is held by a small group of stockholders whose interests may conflict with the interests of our other stockholders.

As of February 27, 2017, Bronicki and FIMI beneficially own, collectively, approximately 21.08% of our outstanding common stock. Bronicki and FIMI are parties to a shareholder rights agreement that, among other things, includes joint voting and other arrangements that affect us and our subsidiaries. The agreement expires on May 22, 2017. As a result of these stockholders’ beneficial ownership of our outstanding common stock, and taking into consideration the shareholders rights agreement between them, they could exert significant influence on the election of our directors and decisions on matters submitted to a vote of our shareholders, including mergers, consolidations and the sale of all or substantially all of our assets. This concentration of ownership of our shares could delay or prevent proxy contests, mergers, tender offers, or other purchases of our shares that might otherwise give our stockholders the opportunity to realize a premium over the then-prevailing market price for our shares. This concentration of ownership may also adversely affect our stock price.

The price of our common stock may fluctuate substantially and your investment may decline in value.

The market price of our common stock may be highly volatile and may fluctuate substantially due to many factors, including:

● actual or anticipated fluctuations in our results of operations including as a result of seasonal variations in our Electricity segment-based revenues or variations from year-to-year in our Product segment-based revenues;

● variance in our financial performance from the expectations of market analysts;

● conditions and trends in the end markets we serve, and changes in the estimation of the size and growth rate of these markets;

● our ability to integrate acquisitions such as our acquisition of substantially all of VEI's business and assets that we expect to close in early 2017;

● announcements of significant contracts by us or our competitors;

● changes in our pricing policies or the pricing policies of our competitors;

● restatements of historical financial results and changes in financial forecasts;

● loss of one or more of our significant customers;

● legislation;

● changes in market valuation or earnings of our competitors;

● the trading volume of our common stock;

● the trading of our common stock on multiple trading markets, which takes place in different currencies and at different times; and

● general economic conditions.

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In addition, the stock market in general, and the NYSE and the market for energy companies in particular, have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of particular companies affected. These broad market and industry factors may materially harm the market price of our common stock, regardless of our operating performance. In the past, following periods of volatility in the market price of a company’s securities, securities class-action litigation has often been instituted against that company. Such litigation, if instituted against us, could result in substantial costs and a diversion of management’s attention and resources, which could materially harm our business, financial condition, future results and cash flow.

Future sales of common stock by some of our existing stockholders could cause our stock price to decline.

As of the date of this report, FIMI holds approximately 13.97% of our outstanding common stock, Bronicki holds approximately 7.11% of our outstanding common stock, and some of our directors, officers and employees also hold shares of our outstanding common stock. Sales of such shares in the public market, as well as shares we may issue upon exercise of outstanding options, could cause the market price of our common stock to decline. We are party to several agreements with FIMI and Bronicki, including (1) a registration rights agreement whereby FIMI and Bronicki may require us to register our common stock held by them with the SEC or to include our common stock held by them in an offering and sale by us, and (2) voting neutralization agreements that, among other things, restrict their ability to sell our common stock held by them.

Provisions in our charter documents and Delaware law may delay, prevent or deter an acquisition of us, which could adversely affect the value of our common stock.

Our restated certificate of incorporation and our bylaws contain provisions that could make it harder for a third party to acquire us without the consent of our Board of Directors. These provisions include procedural requirements relating to stockholder meetings and stockholder proposals that could make stockholder actions more difficult. Our Board of Directors is classified into three classes of directors serving staggered, three-year terms and directors may be removed only for cause. Any vacancy on the Board of Directors may be filled only by the vote of the majority of directors then in office. Delaware law also imposes some restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.

Regulations related to conflict minerals may force us to incur additional expenses and may damage our relationship with certain customers.

On August 22, 2012, the SEC adopted requirements regarding mandatory disclosure for companies regarding their use of "conflict minerals" (including tantalum, tin, tungsten and gold) in their products. In general, while we do not directly purchase or use any of these “conflict minerals” as raw materials in the products we manufacture or as part of our manufacturing processes, we will need to examine whether such minerals are contained in the products supplied to us by third parties and, if so, whether such minerals originate from the Democratic Republic of Congo or adjoining countries. If we utilize any of these minerals and they are necessary to the production or functionality of any of our products or products we are contracted to manufacture, we will need to conduct specified due diligence activities and file with the SEC a report disclosing, among others, whether such minerals originate from the Democratic Republic of Congo or adjoining countries. The implementation of these SEC rules could adversely affect the sourcing, availability and pricing of minerals used in the manufacture of certain components incorporated in our products. In addition, we expect to incur additional costs to comply with the disclosure requirements, including costs related to determining the source of any of the relevant minerals and metals used in our products, and possibly additional expenses related to any changes to our products we may decide are advisable based upon our due diligence findings. Since our supply chain is complex, we may not be able to sufficiently verify the origins for these minerals and metals used in our products through the diligence procedures that we implement, which may harm our reputation. In such event, we may also face difficulties in satisfying customers who require that all of the components of our products are certified as conflict mineral free.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

We currently lease corporate offices at 6225 Neil Road, Reno, Nevada 89511-1136. We also occupy an approximately 807,000 square foot office and manufacturing facility located in the Industrial Park of Yavne, Israel, which we lease from the Israel Land Administration. See Item 13 — “Certain Relationships and Related Transactions”. We also lease small offices in each of the countries in which we operate.

We believe that our current facilities will be adequate for our operations as currently conducted.

Each of our power plants is located on property leased or owned by us or one of our subsidiaries, or is a property that is subject to a concession agreement.

Information and descriptions of our plants and properties are included in Item 1 — “Business”, of this annual report.

ITEM 3. LEGAL PROCEEDINGS

There were no material developments in any legal proceedings to which the Company was a party during fiscal year 2016, other than as described below.

● Jon Olson and Hilary Wilt, together with Puna Pono Alliance filed a complaint on February 17, 2015 in the Third Circuit Court for the State of Hawaii, requesting declaratory and injunctive relief requiring that PGV comply with an ordinance that the plaintiffs allege will prohibit PGV from engaging in night drilling operations at its KS-16 well site. On May 17, 2015, the original complaint was amended to add the county of Hawaii and the State of Hawaii Department of Land and Natural Resources as defendants to the case. On October 10, 2016, the court issued its decision in response to each of the plaintiffs’ and defendants’ motions for summary judgment, denying plaintiffs’ motion and granting defendant PGV's and the County of Hawaii’s cross motions for summary judgment, effectively rendering the plaintiffs’ action moot. On January 17, 2017, the plaintiffs filed a notice of appeal of the October 10, 2016 decision.  Procedural issues as to the ability of the plaintiffs to appeal the decision at this time, including the jurisdiction of the appellate court to near the appeal, are also before the court.

● On July 8, 2014, Global Community Monitor, LiUNA, and two residents of Bishop, California filed a complaint in the U.S. District Court for the Eastern District of California, alleging that Mammoth Pacific, L.P., the Company and Ormat Nevada are operating three geothermal generating plants in Mammoth Lakes, California (MP-1, MP-II and PLES-I) in violation of the federal Clean Air Act and Great Basin Unified Air Pollution Control District rules. On June 26, 2015, in response to a motion by the defendants, the court dismissed all but one of the plaintiffs’ causes of action. On January 6, 2017, the court issued its order regarding several pending motions, including plaintiffs’ motion for partial summary judgment, defendants' motion for summary judgment, defendants' motion to exclude and defendants' motion for leave to file a sur-reply. The impact of the court’s January 6 order is to deny the plaintiffs’ sole remaining cause of action.

● On April 5, 2012, the International Brotherhood of Electrical Workers Local 1260 (“Union”) filed a petition with the NLRB seeking to organize the operations and maintenance employees at the Puna project.  A global settlement was reached in principle in February 2016, which includes a Union disclaimer of interest, the withdrawal of letters from the Union to the NLRB and signed individual settlement agreements, all of which are immaterial. All issues are now settled and closed.

● In January 2014, Ormat learned that two former employees filed a “qui tam” complaint seeking damages, penalties and other relief of approximately $375 million, alleging that the Company and certain of its subsidiaries (collectively, the “Ormat Parties”) submitted fraudulent applications and certifications to obtain grants for the Puna and North Brawley projects. The U.S. Department of Justice declined to intervene. On October 25, 2016, the parties entered into a final settlement agreement providing for the dismissal of the claim without any admission of wrongdoing by the Ormat Parties and payment of $11 million (inclusive of fees and costs). The settlement amount of $11 million was included in general and administrative expenses in the consolidated statements of operations and comprehensive income for the year ended December 31, 2016. 

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● On March 29, 2016, a former local sales representative in Chile, Aquavant, S.A., filed a claim on the basis of unjust enrichment against Ormat’s subsidiaries in the 27th Civil Court of Santiago, Chile. The claim requests that the court order Ormat to pay Aquavant $4.6 million in connection with its activities in Chile, including the EPC contract for the Cerro Pabellon project and various geothermal concessions, plus 3.75% of Ormat geothermal products sales in Chile over the next 10 years. Pursuant to various petitions submitted by defendants, including a motion describing preliminary, procedural defenses, on August 18, 2016, and then on October 10, 2016, the 27th Civil Court issued a number of decisions, which include removal of the case to the 11th Civil Court of Santiago, thereby delaying a determination on the larger issues of jurisdiction and competency of the Chilean courts as a substantive (and not procedural) defense.   The Company believes that it has valid defenses under law, and intends to defend itself vigorously.

●  On August 5, 2016, George Douvris, Stephanie Douvris, Michael Hale, Cheryl Cacocci, Hillary E. Wilt and Christina Bryan, acting for themselves and on behalf of all other similarly situated residents of the lower Puna District, filed a complaint in the Third Circuit Court for the State of Hawaii seeking certification of a class action for preliminary and permanent injunctive relief, consequential and punitive damages, attorney’s fees and statutory interest against PGV and other presently unknown defendants. The complaint purports that injuries and other damages in an undisclosed amount were caused to the plaintiffs as a result of an alleged toxic release by PGV in the wake of Hurricane Iselle in August 2014. On August 25, 2016, the Company filed to remove the case to the U.S. District Court for the District of Hawaii. On December 12, 2016, the District Court granted plaintiffs’ motion for joinder of HELCO as an additional defendant, to amend the complaint, and to remand the case back to the Third Circuit Court. The Company believes that it has valid defenses under law, and intends to defend itself vigorously.

● On May 21, 2014, Elko County, Nevada appealed to the Supreme Court of Nevada the Nevada Governor's Office of Energy’s award of an energy tax abatement to ORNI 42 LLC for our Tuscarora power plant. Lander County, Nevada similarly appealed the Office of Energy’s Award of an energy tax abatement to ORNI 39 LLC for one of our McGinness Hills power plants. Both of the appeals request that the Court overturn the Office of Energy’s decision and deny, retroactively and going forward, the tax abatement benefits for the full 20 year period, valued at approximately $18.6 million for our McGinness Hills power plant and approximately $6.2 million for our Tuscarora power plant, of which only a small portion was utilized as of September 30, 2016. Following full briefing on both plaintiffs’ and defendants’ motions for summary judgment, on December 21, 2016, the Supreme Court of Nevada issued its Order of Affirmance of the judgement of the District Court denying the petitions for judicial review of both Lander County and Elko County, and affirming ORNI 39 and ORNI 42's rights to obtain the partial property tax abatements for their respective facilities.

●  On June 20, 2016, Nadia Garcia, individually and as successor in interest to Thomas Garcia Valenzuela, and as guardian ad litem to Emerie Garcia, Khamilla Garcia and Reyene Adam, filed a complaint against Ormat Technologies, Ormat Nevada and Ormesa LLC in the Superior Court of Imperial County seeking unspecified monetary damages. The complaint alleges that the Ormat defendants caused the wrongful death, personal injury and other harm to Thomas Garcia when he was employed by Martin Hydroblasting Services, Inc. and suffered injuries leading to his death while performing work at the Ormesa plant site on or around March 31, 2016. Early discovery and conferences are underway. The insurer of the deceased’s employer and Ormat’s insurer have accepted tender of this claim and are providing Ormat with a defense in the lawsuit, subject to reservation of rights to deny coverage under the policy and under the law.

In addition, from time to time, the Company is named as a party to various other lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our business. These actions typically seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to such lawsuits, claims and proceedings, the Company accrues reserves when a loss is probable and the amount of such loss can be reasonably estimated. It is the opinion of the Company’s management that the outcome of these proceedings, individually and collectively, will not be material to the Company’s consolidated financial statements as a whole.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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

Our common stock is traded on the NYSE under the symbol “ORA” effective since November 11, 2004. Prior to November 11, 2004, there was no public market for our stock. Effective on February 10, 2015, our common stock also began trading on the TASE.

As of February 27, 2017, there were 18 record holders of the Company’s common stock. On February 27, 2017, our stock’s closing price as reported on the NYSE was $56.77 per share.

Dividends

We have adopted a dividend policy pursuant to which we currently expect to distribute at least 20% of our annual profits available for distribution by way of quarterly dividends. In determining whether there are profits available for distribution, our Board of Directors will take into account our business plan and current and expected obligations, and no distribution will be made that in the judgment of our Board of Directors would prevent us from meeting such business plan or obligations.

Notwithstanding this policy, dividends will be paid only when, as and if approved by our Board of Directors out of funds legally available therefor. The actual amount and timing of dividend payments will depend upon our financial condition, results of operations, business prospects and such other matters as the Board may deem relevant from time to time. Even if profits are available for the payment of dividends, the Board of Directors could determine that such profits should be retained for an extended period of time, used for working capital purposes, expansion or acquisition of businesses or any other appropriate purpose. As a holding company, we are dependent upon the earnings and cash flow of our subsidiaries in order to fund any dividend distributions and, as a result, we may not be able to pay dividends in accordance with our policy. Our Board of Directors may, from time to time, examine our dividend policy and may, in its absolute discretion, change such policy. In addition to the required Board of Directors’ approval for the payment of dividends, the Company can declare as dividends no more than 35% of annual net income as dividends due to restrictions related to its third-party debt (see Note 25 to our consolidated financial statements set forth in Item 8 of this annual report).

We have declared the following dividends over the past two years:

Date Declared	Dividend Amount per Share		Record Date	Payment Date
November 3, 2015	$	0.06	November 18, 2015	December 2, 2015
February 23, 2016	$	0.31	March 15, 2016	March 29, 2016
May 4, 2016	$	0.07	May 18, 2016	May 24, 2016
August 2, 2016	$	0.07	August 16, 2016	August 30, 2016
November 7, 2016	$	0.07	November 21, 2016	December 6, 2016
February 28 2017	$	0.17	March 15, 2017	March 29, 2017

High/Low Stock Prices 

The following table sets forth the high and low sales prices of our common stock for the years ended December 31, 2015 and 2016, and from January 1, 2016 until February 27, 2016:

	First Quarter 2015		Second Quarter 2015		Third Quarter 2015		Fourth Quarter 2015		First Quarter 2016		Second Quarter 2016		Third Quarter 2016		Fourth Quarter 2016		January 1 to February 27, 2017
High	$	38	$	40	$	41	$	38	$	41.56	$	44.45	$	50.87	$	53.71	$	57.59
Low:	$	26	$	36	$	34	$	34	$	33.29	$	40.24	$	43.19	$	46.01	$	51.64

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Stock Performance Graph

The following performance graph represents the cumulative total shareholder return for the period November 11, 2004 (the date upon which trading of the Company’s common stock commenced) through December 31, 2016 for our common stock, compared to the Standard and Poor’s Composite 500 Index, and two peer groups.

Comparison of Cumulative Returns for the Period November 11, 2004 through December 31, 2016

	For the Year Ended December 31,
	2004	2005	2006	2007	2008	2009	2010	2011	2012	2013	2014	2015	2016
Ormat Technologies Inc	9%	74%	145%	267%	112%	152%	97%	20%	29%	81%	81%	143%	258%
Standard & Poor's Composite 500 Index	8%	11%	26%	31%	-20%	-1%	12%	12%	27%	65%	84%	82%	100%
NEX - renewable Index	9%	30%	74%	174%	7%	50%	28%	-23%	-28%	12%	11%	7%	-2%
IPP Peers*	22%	26%	79%	79%	77%	107%	119%	131%	165%	187%	222%	111%	89%
Renewable Peers*	41%	19%	63%	204%	20%	45%	-25%	-22%	-30%	-42%	-23%	17%	-2%

     * IPP Peers are The AES Corporation, NRG Energy Inc., Calpine Corporation and Covanta Holding Corp.

     ** Renewable Energy (Renewable) Peers are Acciona S.A. and U.S. Geothermal Inc.

The above Stock Performance Graph shall not be deemed to be soliciting material or to be filed with the SEC under the Securities Act and the Exchange Act except to the extent that the Company specifically requests that such information be treated as soliciting material or specifically incorporates it by reference into a filing under the Securities Act or the Exchange Act.

Equity Compensation Plan Information

For information on our equity compensation plan, refer to Item 12 — “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters”.

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth our selected consolidated financial data for the years ended and at the dates indicated. We have derived the selected consolidated financial data for the years ended December 31, 2016, 2015 and 2014 and as of December 31, 2016 and 2015 from our audited consolidated financial statements set forth in Item 8 of this annual report. We have derived the selected consolidated financial data for the years ended December 31, 2013 and 2012 and as of December 31, 2014, 2013 and 2012 from our audited consolidated financial statements not included herein.

The information set forth below should be read in conjunction with Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements, including the notes thereto, set forth in Item 8 of this annual report.

	Year Ended December 31,
	2016			2015			2014			2013			2012
	(Dollars in thousands, except per share data)
Statements of Operations Data:
Revenues:
Electricity	$	436,292		$	375,920		$	382,301		$	329,747		$	314,894
Product		226,299			218,724			177,223			203,492			186,879
Total revenues		662,591			594,644			559,524			533,239			501,773
Cost of revenues:
Electricity		261,573			242,612			246,630			232,874			237,415
Product		130,223			133,753			109,143			140,547			135,346
Total cost of revenues		391,796			376,365			355,773			373,421			372,761
Gross profit		270,795			218,279			203,751			159,818			129,012
Operating expenses:
Research and development expenses		2,762			1,780			783			4,965			6,108
Selling and marketing expenses		16,424			16,077			15,425			24,613			15,718
General and administrative expenses		46,710			34,782			28,614			29,188			28,066
Impairment charge		—			—			—			—			236,377
Write-off of unsuccessful exploration activities		3,017			1,579			15,439			4,094			2,639
Operating Income (loss)		201,882			164,061			143,490			96,958			(159,896	)
Other income (expense):
Interest income		971			297			312			1,332			1,201
Interest expense, net		(67,389	)		(72,577	)		(84,654	)		(73,776	)		(64,069	)
Derivatives and foreign currency transaction gains (losses)		(5,534	)		(1,622	)		(5,839	)		5,085			242
Income attributable to sale of tax benefits		16,503			25,431			24,143			19,945			10,127
Gain from sale of property, plant and equipment		—			—			7,628			—			—
Other non-operating income (expense), net		(5,345	)		(1,991	)		756			1,592			590
Income (loss) from continuing operations, before income taxes and equity in income (losses) of investees		141,088			113,599			85,836			51,136			(211,805	)
Income tax (provision) benefit		(31,837	)		15,258			(27,608	)		(13,552	)		(1,827	)
Equity in losses of investees, net		(7,735	)		(5,508	)		(3,213	)		(250	)		(2,522	)
Net Income (loss)		101,516			123,349			55,015			42,031			(212,607	)
Net income attributable to noncontrolling interest		(7,586	)		(3,776	)		(833	)		(793	)		(414	)
Net income (loss) attributable to the Company's stockholders	$	93,930		$	119,573		$	54,182		$	41,238		$	(213,021	)

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	Year Ended December 31,
	2016		2015		2014		2013		2012
	(Dollars in thousands, except per share data)
Earnings (loss) per share attributable to the Company's stockholders:
Basic:
Net Income (loss)	$	1.90	$	2.46	$	1.19	$	0.91	$	(4.69	)
Diluted:
Net income (loss)	$	1.87	$	2.43	$	1.18	$	0.91	$	(4.69	)
Weighted average number of shares used in computation of earnings (loss) per share attributable to the Company's stockholders:
Basic		49,469		48,562		45,508		45,440		45,431
Diluted		50,140		49,187		45,859		45,475		45,431
Dividend per share declared	$	0.52	$	0.26	$	0.21	$	0.08	$	0.08
Balance Sheet Data (at end of year):
Cash and cash equivalents	$	230,214		185,919		40,230		57,354		66,628
Working capital		283,579		186,635		68,121		103,001		64,100
Property, plant and equipment, net (including construction-in process)		1,863,087		1,808,170		1,734,359		1,741,163		1,649,014
Total assets		2,461,569		2,273,982		2,101,525		2,138,674		2,064,631
Long-term debt (including current portion)		938,844		901,403		981,379		1,057,098		1,008,036
Equity		1,170,007		1,083,874		786,746		745,111		695,607

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

You should read the following discussion and analysis of our results of operations, financial condition and liquidity in conjunction with our consolidated financial statements and the related notes. Some of the information contained in this discussion and analysis or set forth elsewhere in this annual report including information with respect to our plans and strategies for our business, statements regarding the industry outlook, our expectations regarding the future performance of our business, and the other non-historical statements contained herein are forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements.” You should also review Item 1A — “Risk Factors” for a discussion of important factors that could cause actual results to differ materially from the results described herein or implied by such forward-looking statements.

General

Overview

We are a leading vertically integrated company that is currently primarily engaged in the geothermal and recovered energy power business. With the objective of becoming a leading global provider of renewable energy, we focus on several key initiatives, under our new strategic plan, as described below.

We design, develop, build, sell, own, and operate clean, environmentally friendly geothermal and recovered energy-based power plants, usually using equipment that we design and manufacture.

Our geothermal power plants include both power plants that we have built and power plants that we have acquired, while we have built all of our recovered energy-based plants. We currently conduct our business activities in two business segments:

● The Electricity segment — in this segment we develop, build, own and operate geothermal and recovered energy-based power plants in the U.S. and geothermal power plants in other countries around the world, and sell the electricity they generate and in the future, we plan to include services and other revenues derived from activity in the demand response and storage market as described below; and

● The Product segment — in this segment we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation and remote power units and provide services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy-based power plants and in the future, other power generating units such as Solar PV and energy storage.

We intend to expand our operations to include demand response, energy management and storage. We recently signed an agreement to acquire substantially all of the business and assets of  VEI, a privately held Philadelphia-based company with nearly a decade of expertise and leadership in demand response, energy management and storage. The acquired assets will be owned by our newly established wholly owned subsidiary, Viridity. The acquisition, which is expected to be close in early 2017, will mark Ormat’s entry into the growing energy storage and demand response markets. We intend to use Viridity to accelerate long-term growth, expand our market presence, and further develop VEI’s demand response VPower™ software platform and energy storage services. We plan to continue to provide services and products to existing customers of the acquired business, while expanding into new geographies and targeting a broader potential customer base.

Both our Electricity segment and Product segment operations are conducted in the U.S. and the rest of the world. Our current generating portfolio includes geothermal plants in the U.S., Guatemala, Kenya and Guadeloupe as well as REG plants in the U.S.

For the year ended December 31, 2016, our total revenues increased by 11.4% (from $594.6 million to $662.6 million) over the previous year.

For the year ended December 31, 2016, Electricity segment revenues were $436.3 million, compared to $375.9 million for the year ended December 31, 2015, an increase of 16.1% . Product segment revenues for the year ended December 31, 2016 were $226.3 million, compared to $218.7 million for the year ended December 31, 2015, an increase of 3.5%.

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During the years ended December 31, 2016 and 2015, our consolidated power plants generated 5,396,959 MWh and 4,835,109 MWh, respectively, an increase of 11.6%

For the year ended December 31, 2016, our Electricity segment generated approximately 65.8% of our total revenues (63.2% in 2015), while our Product segment generated approximately 34.2% of our total revenues (36.8% in 2015).

For the year ended December 31, 2016, approximately 86% of our Electricity segment revenues were from PPAs with fixed energy rates which are not affected by fluctuations in energy commodity prices. We have variable price PPAs in California and Hawaii, which provide for payments based on the local utilities’ avoided cost, which is the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others, as follows:

● the energy rates under the PPAs in California for each of the Ormesa complex, Heber 2 power plant in the Heber complex and the G2 power plant in the Mammoth complex, a total of approximately 90 MW, change primarily based on fluctuations in natural gas prices; and

● the prices paid for the electricity pursuant to the 25 MW PPA for the Puna complex in Hawaii change primarily due to variations in the price of oil as well as other commodities.

We recently reduced our economic exposure to fluctuations in the price of natural gas from February 2017 until December 2017, and before we reduced our economic exposure to fluctuations in the price of natural gas and oil from January 1, 2015 to March 31, 2015 and June 1, 2015 to December 31, 2015 and from February 3, 2016 until December 29, 2016, by entering into derivatives transactions. For the year ended December 31, 2016, we recorded a net loss of $2.6 million under Derivatives and foreign currency transaction gains (losses).

To comply with obligations under their respective PPAs, certain of our project subsidiaries are structured as special purpose, bankruptcy remote entities and their assets and liabilities are ring-fenced. Such assets are not generally available to pay our debt other than debt at the respective project subsidiary level.  However, these project subsidiaries are allowed to pay dividends and make distributions of cash flows generated by their assets to us subject in some cases to restrictions in debt instruments, as described below.

Electricity segment revenues are also subject to seasonal variations and can be affected by higher-than-average ambient temperatures, as described below under “Seasonality”.

Revenues attributable to our Product segment are based on the sale of equipment, EPC contracts and the provision of various services to our customers. Product segment revenues may vary from period to period because of the timing of our receipt of purchase orders and the progress of our equipment manufacturing and execution of the relevant project.

Our management assesses the performance of our two operating segments differently. In the case of our Electricity segment, when making decisions about potential acquisitions or the development of new projects, management typically focuses on the internal rate of return of the relevant investment, technical and geological matters and other business considerations. Management evaluates our operating power plants based on revenues, expenses, and EBITDA, and our projects that are under development based on costs attributable to each such project. Management evaluates the performance of our Product segment based on the timely delivery of our products, performance quality of our products, revenues and costs actually incurred to complete customer orders compared to the costs originally budgeted for such orders.

Trends and Uncertainties

Trends, factors and uncertainties may impact our operations and financial condition, including many that we do not or cannot foresee, we believe that our results of operations and financial condition for the foreseeable future will be primarily affected by the following trends, factors and uncertainties that are from time to time subject to market cycle:

● There has been increased demand for energy generated from geothermal and other renewable resources in the U.S. as costs for electricity generated from renewable resources have become more competitive. Much of this is attributable to legislative and regulatory requirements and incentives, such as state RPS and federal tax credits such as PTCs or ITCs (which are discussed in more detail in the section entitled “Government Grants and Tax Benefits” below). We believe that future demand for energy generated from geothermal and other renewable resources in the U.S. will be driven mainly by further commitment and implementation of state RPS and greenhouse gas initiatives.

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● We accelerated our efforts to expand business development activities in developing countries where geothermal is considered a local resource that can provide stable and cost effective solution to increase access to power. We expect that a variety of local governmental initiatives will create new opportunities for the development of new projects, as well as create additional markets for our products. These initiatives include the award of long-term contracts to independent power generators, the creation of competitive wholesale markets for selling and trading energy, capacity and related energy products and the adoption of programs designed to encourage “clean” renewable and sustainable energy sources.

● We expect to continue to generate the majority of our revenues from our Electricity segment through the sale of electricity from our power plants. All of our current revenues from the sale of electricity are derived from payments under long-term PPAs related to fully-contracted power plants. We also intend to continue to pursue opportunities, as they arise in our recovered energy business, in the Solar PV sector, in the energy storage market and in other forms of clean energy. In addition, pursuant to our strategic plan, we acquired a business in the demand response and energy storage that generates revenues derived mainly from software license fee and services, and we are also pursuing PPAs with enterprises that will increase our potential customer base.

● We have adopted a new strategic plan for growth of our company, in terms of geographic scope, customer base, and technology platforms covered by our product and service offerings, with a focus on increasing net income from operations.  Under this plan, we will continue to focus on organic growth and increasing operational efficiency of our existing business lines.  In addition, we are actively pursuing acquisition opportunities, both in our existing business lines and the solar power generation and energy storage businesses targeted as part of the plan. Examples include our acquisition of the Bouillante geothermal power plant on Guadeloupe Island and our recent entry into an agreement to acquire substantially all of the business and assets of VEI, which we plan to operate in the demand response and storage markets. We will face a number of challenges and uncertainties in implementing this plan, including integration of recently acquired assets, and we may revise elements of the plan in response to market conditions or other factors as we move forward with the plan.

● In the Electricity segment, we expect intense domestic competition from the solar and wind power generation industries to continue and increase. While we believe the expected demand for renewable energy will be large enough to accommodate increased competition, any such increase in competition, including increasing amountsof renewable energy under contract as well as any further decline in natural gas prices due to increased production which can affect the market price for electricity may contribute to a reduction in electricity prices. However, despite increased competition from the solar and wind power generation industries, we believe that base load electricity, such as geothermal-based energy, will continue to be an important source of renewable energy in areas with commercially viable geothermal resources. Also, we believe that geothermal power plants can positively impact electrical grid stability and provide valuable ancillary services because of their base load nature. In the geothermal industry, due to reduced competition for geothermal leases we have experienced a decrease in the upfront fee required to secure geothermal leases.

● In the Product segment, we have experienced increased competition from binary power plant equipment suppliers including the major steam turbine manufacturers. While we believe that we have a distinct competitive advantage based on our accumulated experience and current worldwide share of installed binary generation capacity, an increase in competition may impact our ability to secure new purchase orders from potential customers. The increased competition may also lead to further reduction in the prices that we are able to charge for our binary equipment, which in turn may reduce our profitability.

● The 38 MW Puna complex has three PPAs, one of which (the 25 MW PPA) has a monthly variable energy rate based on the local utility’s avoided costs. A decrease in the price of oil as well as in other commodities will result in a decrease in the incremental cost that the power purchaser avoids by not generating its electrical energy needs from oil, which will result in a reduction of the energy rate that we may charge under this PPA. In order to reduce our exposure to oil we signed fixed rate PPAs for the remaining 13 MW.

● Since May 2012, the pricing under our PPAs for the Ormesa, Mammoth and Heber complexes for a total of 161 MW were variable rate based on SRAC pricing that is impacted by natural gas prices. However, in 2013 and December 2015, we signed new fixed rate PPAs that reduced our current exposure to SRAC by 18 MW and 53 MW respectively, and recently we signed a fixed rate PPA that will reduce our exposure in November 2017 by an additional 40MW. In addition, to further reduce our exposure to natural gas prices, we enter, from time to time, into derivative transactions. In May 2015 we entered into a derivative transaction at a fixed price of $3.00 per MMbtu and reduced our exposure to SRAC in the period from June 1, 2015 until December 31, 2015. In February 2016, we sold call options for total proceeds of $1.9 million at a fixed price of $2.00 per MMbtu to reduce our exposure to SRAC in the period from February 3, 2016 until December 29, 2016. In January 2017 we acquired put options at a strike price of $3 to hedge our exposure to decreasing natural gas prices below $3 per MMbtu.

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● The amounts that we are paid under our PPAs for electricity, capacity and other energy attributes vary for a number of reasons, including:

○ market conditions when the PPA is signed;

○ the competitive environment in the power market where the plant is located and the power and other energy attributes are sold; and

○ in the case of contracts described in the prior bullets with variable pricing components, current oil and natural gas prices.

This means, among other things, that one of the metrics some investors may use to evaluate power plant revenues is an average price per MWh that can fluctuate from year to year. Based on total Electricity segment revenues for those years, we earned, on average, $80.84 and $77.75 per MWh in 2016 and 2015, respectively. Oil and natural gas prices, together with other factors that affect our Electricity segment revenues, could cause changes in our average rate per MWH in the future.

● The viability of a geothermal resource depends on various factors such as the resource temperature, the permeability of the resource (i.e., the ability to get geothermal fluids to the surface) and operational factors relating to the extraction and injection of the geothermal fluids. Such factors, together with the possibility that we may fail to find commercially viable geothermal resources in the future, represent significant uncertainties that we face in connection with our growth expectations.

● As our power plants (including their respective well fields) age, they may require increased maintenance with a resulting decrease in their availability, potentially leading to the imposition of penalties if we are not able to meet the requirements under our PPAs as a result of any decrease in availability.

● Our foreign operations are subject to significant political, hostilities, economic and financial risks, which vary by country. As of the date of this annual report, those risks include security conditions in Israel, the partial privatization of the electricity sector in Guatemala and the political uncertainty currently prevailing in some of the countries in which we operate as further discussed above under “Risk Factors”. Although we maintain among other things political risk insurance for most of our investments in foreign power plants to mitigate these risks, insurance does not provide complete coverage with respect to all such risks.

● The Sarulla 330 MW project was released for construction, and we began to recognize our first Product segment revenues under the supply contract we signed with the EPC contractor in the quarter ended September 30, 2014. In 2017, we expect to derive significant revenues from the supply contract. We expect to generate additional income from our 12.75% equity investment in the Sarulla consortium following the commercial operation of the project. The Sarulla project’s future operations may be impacted by the status of development as discussed above under “Description of Our Power Plants”, various factors which we do not control given our minority position in the consortium, as well as other factors discussed above under “Risk Factors”.

● While we do not see any immediate impact from the failed coup in Turkey on our business and operations, we are monitoring any change in the political environment that may affect our future business and operations in the country. As a major equipment supplier in the Turkish geothermal market we are involved in a number of projects that are currently under construction and plan to continue our marketing efforts to secure new contracts. Our revenue exposure to the Turkish market is increasing and we expect higher exposure in 2017, as we signed significant number of new contracts in Turkey.

● A Turkish sub-contractor provides us with certain local equipment for renewable energy based generating facilities to help us meet our obligations under certain supply agreements in Turkey. The use of local equipment in renewable energy based generating facilities in Turkey entitles such facilities to certain benefits under Turkish law, provided such facilities have obtained an RER Certificate from EMRA, which requires the issuance of a local certificate. If we do not obtain the local certificate, then some of our customers under the relevant supply agreements in Turkey may not be issued a RER Certificate based on the equipment we supply to them, and we will be required to make a payment to such customers equal to the amount of the expected lost benefit.

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● FERC is allowed under PURPA to terminate, upon the request of a utility, the obligation of the utility to purchase the output of a Qualifying Facility if FERC finds that there is an accessible competitive market for energy and capacity from the Qualifying Facility. FERC has granted the California investor owned utilities a waiver of the mandatory purchase obligations from Qualifying Facilities above 20 MW. If the utilities in the regions in which our domestic power plants operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from us upon termination of the existing PPA, which could have an adverse effect on our revenues.

Revenues

We generate our revenues from the sale of electricity from our geothermal and recovered energy-based power plants; the design, manufacture and sale of equipment for electricity generation; and the construction, installation and engineering of power plant equipment.

Revenues attributable to our Electricity segment are derived from the sale of electricity from our power plants pursuant to long-term PPAs. While approximately 86% of our Electricity revenues for the year ended December 31, 2016 were derived from PPAs with fixed price components, we have variable price PPAs in California and Hawaii. Our California SO#4 PPAs totaling 99 MWs are subject to the impact of fluctuations in natural gas prices whereas the prices paid for electricity pursuant to the 25 MW PPA for the Puna complex in Hawaii are impacted by the price of oil as well as other commodities. Accordingly, our revenues from those power plants may fluctuate.

Our Electricity segment revenues are also subject to seasonal variations, as more fully described in “Seasonality” below.

Our PPAs generally provide for energy payments alone, or energy and capacity payments. Generally, capacity payments are payments calculated based on the amount of time that our power plants are available to generate electricity. Some of our PPAs provide for bonus payments in the event that we are able to exceed certain target capacity levels and the potential forfeiture of payments if we fail to meet certain minimum target capacity levels. Energy payments, on the other hand, are payments calculated based on the amount of electrical energy delivered to the relevant power purchaser at a designated delivery point. The rates applicable to such payments are either fixed (subject, in certain cases, to certain adjustments) or are based on the relevant power purchaser’s avoided costs. Our more recent PPAs generally provide for energy payments alone with an obligation to compensate the off-taker for its incremental costs as a result of shortfalls in our supply.

Revenues attributable to our Product segment fluctuate between periods, mainly based on our ability to receive customer orders, the status and timing of such orders, delivery of raw materials and the completion of manufacturing. Larger customer orders for our products are typically the result of our participating in, and winning, tenders or requests for proposals issued by potential customers in connection with projects they are developing. Such projects often take a significant amount of time to design and develop and are subject to various contingencies, such as the customer’s ability to raise the necessary financing for a project. Consequently, we are generally unable to predict the timing of such orders for our products and may not be able to replace existing orders that we have completed with new ones. As a result, revenues from our Product segment fluctuate (sometimes, extensively) from period to period. In both 2014 and 2015, we experienced a significant increase in our Product segment customer orders, which has increased our Product segment backlog. The backlog for our Product segment as of February 27, 2017, is described above in Item 1 — “Business”.

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The following table sets forth a breakdown of our revenues for the years indicated:

	Revenues (dollars in thousands)						% of Revenues for Period Indicated
	Year Ended December 31,						Year Ended December 31,
	2016		2015		2014		2016			2015			2014
Revenues:
Electricity	$	436,292	$	375,920	$	382,301		65.8	%		63.2	%		68.3	%
Product		226,299		218,724		177,223		34.2			36.8			31.7
Total revenues	$	662,591	$	594,644	$	559,524		100.0	%		100.0	%		100.0	%

Geographic Breakdown of Revenues

The following table sets forth the geographic breakdown of the revenues attributable to our Electricity and Product segments for the years indicated:

	Revenues in Thousands						% of Revenues for Period Indicated
	Year Ended December 31,						Year Ended December 31,
	2016		2015		2014		2016			2015			2014
Electricity Segment:
United States	$	288,842	$	261,478	$	268,198		66.2	%		69.6	%		70.2	%
Foreign		147,450		114,442		114,103		33.8			30.4			29.8
Total	$	436,292	$	375,920	$	382,301		100.0	%		100.0	%		100.0	%
Product Segment:
United States	$	18,183	$	19,838	$	17,000		8.0	%		9.1	%		9.6	%
Foreign		208,116		198,886		160,223		92.0			90.9			90.4
Total	$	226,299	$	218,724	$	177,223		100.0	%		100.0	%		100.0	%

The contribution of our domestic and foreign operations within our Electricity segment and Product segment to combined pre-tax income differ in a number of ways.

Electricity Segment. Our Electricity segment domestic revenues were approximately 96% and 128% higher than our Electricity segment foreign revenues for the years ended December 31, 2016 and 2015, respectively. However, domestic operations in our Electricity segment have higher costs of revenues and expenses than the foreign operations in our Electricity segment. Our foreign power plants are located in lower-cost regions, like Kenya, Guatemala and Guadeloupe, which favorably impact payroll and maintenance expenses among other items. They are also newer than most of our domestic power plants and therefore tend to have lower maintenance costs and higher availability factors than our domestic power plants.

Product Segment. Our Product segment foreign revenues were more than 90% of our total Product segment revenues for the years ended December 31, 2016 and 2015. Our Product segment foreign activity also benefits from lower costs of revenues and expenses than Product segment domestic activity such as labor and transportation costs. Accordingly, our Product segment foreign activity contributes more than our Product segment domestic activity to our pre-tax income from operations.

Relative Contributions. While our combined (domestic and foreign) Electricity segment revenues exceeded our combined Product segment revenues by approximately $210.0 million and $157.2 million for the year ended December 31, 2016 and 2015, respectively, (primarily foreign), Product segment revenues resulted in higher pre-tax income from foreign operations for both of those periods.

Seasonality

The prices paid for the electricity generated by some of our domestic power plants pursuant to our PPAs are subject to seasonal variations. The prices (mainly for capacity) paid for electricity under the PPAs with Southern California Edison and PG&E in California for the Heber 2 power plant in the Heber complex, the Mammoth complex, the Ormesa complex, and the North Brawley power plant are higher in the months of June through September. As a result, we receive, and expect to continue to receive in the future, higher revenues from these power plants and complexes during such months. In the winter, our power plants produce more energy principally due to the lower ambient temperature, which has a favorable impact on the energy component of our Electricity revenues. The higher payments payable by Southern California Edison and PG&E in the summer months offset the negative impact on our revenues from lower generation in the summer due to the higher ambient temperature

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Breakdown of Cost of Revenues

Electricity Segment

The principal cost of revenues attributable to our operating power plants includes operation and maintenance expenses comprised of salaries and related employee benefits, equipment expenses, costs of parts and chemicals, costs related to third-party services, lease expenses, royalties, startup and auxiliary electricity purchases, property taxes, insurance and, for some of our projects, purchases of make-up water for use in our cooling towers and also depreciation and amortization. In our California power plants our principal cost of revenues also includes transmission charges and scheduling charges. In some of our Nevada power plants we also incur transmission and wheeling charges. Some of these expenses, such as parts, third-party services and major maintenance, are not incurred on a regular basis. This results in fluctuations in our expenses and our results of operations for individual power plants from quarter to quarter. Payments made to government agencies and private entities on account of site leases where plants are located are included in cost of revenues. Royalty payments, included in cost of revenues, are made as compensation for the right to use certain geothermal resources and are paid as a percentage of the revenues derived from the associated geothermal rights. Royalties constituted approximately 3.9% and 4.1% of Electricity segment revenues for the years ended December 31, 2016 and December 31, 2015, respectively.

Product Segment

The principal cost of revenues attributable to our Product segment includes materials, salaries and related employee benefits, expenses related to subcontracting activities, and transportation expenses. Sales commissions to sales representatives are included in selling and marketing expenses. Some of the principal expenses attributable to our Product segment, such as a portion of the costs related to labor, utilities and other support services are fixed, while others, such as materials, construction, transportation and sales commissions, are variable and may fluctuate significantly, depending on market conditions. As a result, the cost of revenues attributable to our Product segment, expressed as a percentage of total revenues, fluctuates. Another reason for such fluctuation is that in responding to bids for our products, we price our products and services in relation to existing competition and other prevailing market conditions, which may vary substantially from order to order.

Cash and Cash Equivalents

Our cash and cash equivalents, as of December 31, 2016 increased to $230.2 million from $185.9 million as of December 31, 2015. This increase is principally due to: (i) $203.5 million net proceeds from issuance of two new series of senior unsecured bonds; (ii) $159.3 million derived from operating activities during the year ended December 31, 2016; (iii) $92.5 million of proceeds from the senior secured notes issued by our subsidiary that owns our Don A. Campbell 1 power plant; (iv) $50.0 million of proceeds from the loan for our Olkaria 3 complex; (v) $59.9 million representing our share of the proceeds from the Opal Transaction (see “Opal Transaction” below); (vi) $44.1 million net proceeds derived from the issuance of shares to noncontrolling interest and (vii) a net change in restricted cash and cash equivalents of $15.2 million. This increase was partially offset by: (i) prepayment of $249.5 million of senior unsecured bonds; (ii) our use of $151.9 million to fund capital expenditures; (iii) net repayment of $62.1 million of long-term debt; (iv) $6.8 million of cash paid to repurchase a portion of our OFC Senior Secured Notes; (v) $20.1 million net cash paid for the acquisition of GB; and (vi) $64.1 million cash paid to a noncontrolling interest; and (vii) payment of a $25.7 million cash dividend. Our corporate borrowing capacity under committed lines of credit with different commercial banks as of December 31, 2016 was $524.8 million, as described below in “Liquidity and Capital Resources”, of which we have utilized $342.6 million as of December 31, 2016.

Critical Accounting Estimates and Assumptions 

Our significant accounting policies are more fully described in Note 1 to our consolidated financial statements set forth in Item 8 of this annual report. However, certain of our accounting policies are particularly important to an understanding of our financial position and results of operations. In applying these critical accounting estimates and assumptions, our management uses its judgment to determine the appropriate assumptions to be used in making certain estimates. Such estimates are based on management’s historical experience, the terms of existing contracts, management’s observance of trends in the geothermal industry, information provided by our customers and information available to management from other outside sources, as appropriate. Such estimates are subject to an inherent degree of uncertainty and, as a result, actual results could differ from our estimates. Our critical accounting policies include:

• Revenues and Cost of Revenues. Revenues related to the sale of electricity from our geothermal and REG power plants and capacity payments paid in connection with such sales (electricity revenues) are recorded based upon output delivered and capacity provided by such power plants at rates specified pursuant to the relevant PPAs. Revenues related to PPAs accounted for as operating leases with minimum lease rentals which vary over time are generally recognized on a straight-line basis over the term of the PPA.

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Revenues generated from the construction of geothermal and recovered energy-based power plant equipment and other equipment on behalf of third parties (product revenues) are recognized using the percentage of completion method, which requires estimates of future costs over the full term of product delivery. Such cost estimates are made by management based on prior operations and specific project characteristics and designs. If management’s estimates of total estimated costs with respect to our Product segment are inaccurate, then the percentage of completion is inaccurate resulting in an over- or under-estimate of gross margins. As a result, we review and update our cost estimates on significant contracts on a quarterly basis, and at least on an annual basis for all others, or when circumstances change and warrant a modification to a previous estimate. Changes in job performance, job conditions, and estimated profitability, including those arising from the application of penalty provisions in relevant contracts and final contract settlements, may result in revisions to costs and revenues and are recognized in the period in which the revisions are determined. Provisions for estimated losses relating to contracts are made in the period in which such losses are determined. Revenues generated from engineering and operating services and sales of products and parts are recorded once the service is provided or product delivery is made, as applicable.

• Property, Plant and Equipment. We capitalize all costs associated with the acquisition, development and construction of power plant facilities. Major improvements are capitalized and repairs and maintenance (including major maintenance) costs are expensed. We estimate the useful life of our power plants to range between 25 and 30 years. Such estimates are made by management based on factors such as prior operations, the terms of the underlying PPAs, geothermal resources, the location of the assets and specific power plant characteristics and designs. Changes in such estimates could result in useful lives which are either longer or shorter than the depreciable lives of such assets. We periodically re-evaluate the estimated useful life of our power plants and revise the remaining depreciable life on a prospective basis.

We capitalize costs incurred in connection with the exploration and development of geothermal resources beginning when we acquire land rights to the potential geothermal resource. Prior to acquiring land rights, we make an initial assessment that an economically feasible geothermal reservoir is probable on that land using available data and external assessments vetted through our exploration department and occasionally outside service providers. Costs incurred prior to acquiring land rights are expensed. It normally takes two to three years from the time we start active exploration of a particular geothermal resource to the time we have an operating production well, assuming we conclude the resource is commercially viable.

In most cases, we obtain the right to conduct our geothermal development and operations on land owned by the BLM, various states or with private parties. In consideration for certain of these leases, we may pay an up-front non-refundable bonus payment which is a component of the competitive lease process. This payment and other related costs are capitalized and included in construction-in-process. Once we acquire land rights to the potential geothermal resource, we perform additional activities to assess the commercial viability of the resource. Such activities include, among others, conducting surveys and other analyses, obtaining drilling permits, creating access roads to drilling sites, and exploratory drilling which may include temperature gradient holes and/or slim holes. Such costs are capitalized and included in construction-in-process. Once our exploration activities are complete, we finalize our assessment as to the commercial viability of the geothermal resource and either proceed to the construction phase for a power plant or abandon the site. If we decide to abandon a site, all previously capitalized costs associated with the exploration project are written off.

Our assessment of economic viability of an exploration project involves significant management judgment and uncertainties as to whether a commercially viable resource exists at the time we acquire land rights and begin to capitalize such costs. As a result, it is possible that our initial assessment of a geothermal resource may be incorrect and we will have to write-off costs associated with the project that were previously capitalized. For example, during the years ended December 31, 2016, and 2015, we determined that the geothermal resource at two and three of our exploration projects, respectively, would not support commercial operations and as such, we abandoned those sites. As a result of this determination, we expensed $3.0 million and $1.6 million of capitalized costs during the years ended December 31, 2016 and 2015, respectively. Due to the uncertainties inherent in geothermal exploration, these historical impairments may not be indicative of future impairments. Included in construction-in-process are costs related to projects in exploration and development of $54.4 million and $62.9 million at December 31, 2016 and 2015, respectively. Included in this amount, $17.4 million and $26.5 million relates to up-front bonus payments at December 31, 2016 and 2015, respectively.

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• Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of. We evaluate long-lived assets, such as property, plant and equipment and construction-in-process for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Factors which could trigger an impairment include, among others, significant underperformance relative to historical or projected future operating results, significant changes in our use of assets or our overall business strategy, negative industry or economic trends, a determination that an exploration project will not support commercial operations, a determination that a suspended project is not likely to be completed, a significant increase in costs necessary to complete a project, legal factors relating to our business or when we conclude that it is more likely than not that an asset will be disposed of or sold.

We test our operating plants that are operated together as a complex for impairment at the complex level because the cash flows of such plants result from significant shared operating activities. For example, the operating power plants in a complex are managed under a combined operation management generally with one central control room that controls and one maintenance group that services all of the power plants in a complex. As a result, the cash flows from individual plants within a complex are not largely independent of the cash flows of other plants within the complex. We test for impairment of our operating plants which are not operated as a complex, as well as our projects under exploration, development or construction that are not part of an existing complex, at the plant or project level. To the extent an operating plant becomes part of a complex in the future, we will test for impairment at the complex level.

Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated future net undiscounted cash flows expected to be generated by the asset. The significant assumptions that we use in estimating our undiscounted future cash flows include (i) projected generating capacity of the power plant and rates to be received under the respective PPA and (ii) projected operating expenses of the relevant power plant. Estimates of future cash flows used to test recoverability of a long-lived asset under development also include cash flows associated with all future expenditures necessary to develop the asset. If future cash flows are less than the assumptions we used in such estimates, we may incur impairment losses in the future that could be material to our financial condition and/or results of operations.

If our assets are considered to be impaired, the impairment to be recognized is the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. We believe that for the year ended December 31, 2016, no impairment exists for any of our long-lived assets; however, estimates as to the recoverability of such assets may change based on revised circumstances. Estimates of the fair value of assets require estimating useful lives and selecting a discount rate that reflects the risk inherent in future cash flows.

• Obligations Associated with the Retirement of Long-Lived Assets. We record the fair market value of legal liabilities related to the retirement of our assets in the period in which such liabilities are incurred. These liabilities include our obligation to plug wells upon termination of our operating activities, the dismantling of our power plants upon cessation of our operations, and the performance of certain remedial measures related to the land on which such operations were conducted. When a new liability for an asset retirement obligation is recorded, we capitalize the costs of such liability by increasing the carrying amount of the related long-lived asset. Such liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. At retirement, we either settle the obligation for its recorded amount or report either a gain or a loss with respect thereto. Estimates of the costs associated with asset retirement obligations are based on factors such as prior operations, the location of the assets and specific power plant characteristics. We review and update our cost estimates periodically and adjust our asset retirement obligations in the period in which the revisions are determined. If actual results are not consistent with our assumptions used in estimating our asset retirement obligations, we may incur additional losses that could be material to our financial condition or results of operations.

• Accounting for Income Taxes. Significant estimates are required to arrive at our consolidated income tax provision and other tax balances. This process requires us to estimate our actual current tax exposure and to make an assessment of temporary differences resulting from differing treatments of items for tax and accounting purposes. Such differences result in deferred tax assets and liabilities which are included in our consolidated balance sheets. For those jurisdictions where the projected operating results indicate that realization of our net deferred tax assets is not more likely than not, a valuation allowance is recorded.

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We evaluate our ability to utilize the deferred tax assets quarterly and assess the need for the valuation allowance. In assessing the need for a valuation allowance, we estimate future taxable income, considering the feasibility of ongoing tax planning strategies and the realization of tax loss carryforwards. Valuation allowances related to deferred tax assets can be affected by changes in tax laws, statutory tax rates, and future taxable income. We have recorded a valuation allowance related to our U.S. deferred tax assets. In the future, if there is sufficient evidence that we will be able to generate sufficient future taxable income in the U.S., we may be required to reduce this valuation allowance, resulting in income tax benefits in our consolidated statement of operations.

In the ordinary course of business, there is inherent uncertainty in quantifying our income tax positions. We assess our income tax positions and record tax benefits for all years subject to examination based upon management’s evaluation of the facts, circumstances and information available at the reporting date. For those tax positions where it is more likely than not that a tax benefit will be sustained, which is greater than 50% likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information, we recognize between 0 to 100% of the tax benefit. For those income tax positions where it is not more likely than not that a tax benefit will be sustained, we do not recognize any tax benefit in the consolidated financial statements. Resolution of these uncertainties in a manner inconsistent with our expectations could have a material impact on our financial condition or results of operations.

New Accounting Pronouncements

See Note 1 to our consolidated financial statements set forth in Item 8 of this annual report for information regarding new accounting pronouncements.

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Results of Operations

Our historical operating results in dollars and as a percentage of total revenues are presented below. A comparison of the different years described below may be of limited utility due to (i) our recent construction or disposition of new power plants and enhancement of acquired power plants and (ii) fluctuation in revenues from our Product segment.

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands, except per share data)
Revenues:
Electricity	$	436,292		$	375,920		$	382,301
Product		226,299			218,724			177,223
		662,591			594,644			559,524
Cost of revenues:
Electricity		261,573			242,612			246,630
Product		130,223			133,753			109,143
		391,796			376,365			355,773
Gross profit
Electricity		174,719			133,308			135,671
Product		96,076			84,971			68,080
		270,795			218,279			203,751
Operating expenses:
Research and development expenses		2,762			1,780			783
Selling and marketing expenses		16,424			16,077			15,425
General and administrative expenses		46,710			34,782			28,614
Write-off of unsuccessful exploration activities		3,017			1,579			15,439
Operating income		201,882			164,061			143,490
Other income (expense):
Interest income		971			297			312
Interest expense, net		(67,389	)		(72,577	)		(84,654	)
Derivatives and foreign currency transaction gains (losses)		(5,534	)		(1,622	)		(5,839	)
Income attributable to sale of tax benefits		16,503			25,431			24,143
Gain from sale of property, plant and equipment		—			—			7,628
Other non-operating income (expense), net		(5,345	)		(1,991	)		756
Income from continuing operations before income taxes equity in income of investees and equity in losses of investees		141,088			113,599			85,836
Income tax (provision) benefit		(31,837	)		15,258			(27,608	)
Equity in losses of investees, net		(7,735	)		(5,508	)		(3,213	)
Net income		101,516			123,349			55,015
Net income attributable to noncontrolling interest		(7,586	)		(3,776	)		(833	)
Net income attributable to the Company's stockholders	$	93,930		$	119,573		$	54,182
Earnings per share attributable to the Company's stockholders:
Basic:
Net income	$	1.90		$	2.46		$	1.19
Diluted:
Net income	$	1.87		$	2.43		$	1.18
Weighted average number of shares used in computation of earnings per share attributable to the Company's stockholders:
Basic		49,469			48,562			45,508
Diluted		50,140			49,187			45,859

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	Year Ended December 31,
	2016			2015			2014
Revenues:
Electricity		65.8	%		63.2	%		68.3	%
Product		34.2			36.8			31.7
		100.0			100.0			100.0
Cost of revenues:
Electricity		60.0			64.5			64.5
Product		57.5			61.2			61.6
		59.1			63.3			63.6
Gross margin
Electricity		40.0			35.5			35.5
Product		42.5			38.8			38.4
		40.9			36.7			36.4
Operating expenses:
Research and development expenses		0.4			0.3			0.1
Selling and marketing expenses		2.5			2.7			2.8
General and administrative expenses		7.0			5.8			5.1
Write-off of unsuccessful exploration activities		0.5			0.3			2.8
Operating income		30.5			27.6			25.6
Other income (expense):
Interest income		0.1			0.0			0.1
Interest expense, net		(10.2	)		(12.2	)		(15.1	)
Derivatives and foreign currency transaction gains (losses)		(0.8	)		(0.3	)		(1.0	)
Income attributable to sale of tax benefits		2.5			4.3			4.3
Gain from sale of property, plant and equipment		0.0			0.0			1.4
Other non-operating income (expense), net		(0.8	)		(0.3	)		0.1
Income from continuing operations before income taxes and equity in losses of investees		21.3			19.1			15.3
Income tax (provision) benefit		(4.8	)		2.6			(4.9	)
Equity in losses of investees, net		(1.2	)		(0.9	)		(0.6	)
Net income		15.3			20.7			9.8
Net income attributable to noncontrolling interest		(1.1	)		(0.6	)		(0.1	)
Net income attributable to the Company's stockholders		14.2	%		20.1	%		9.7	%

Comparison of the Year Ended December 31, 2016 and the Year Ended December 31, 2015

Total Revenues

Total revenues for the year ended December 31, 2016 were $662.6 million, compared to $594.6 million for the year ended December 31, 2015, representing a 11.4% increase from the prior period. This increase was attributable to both our Electricity and Product segments, in which revenues increased by 16.1% and 3.5%, respectively, compared to the corresponding period in 2015.

Electricity Segment

Revenues attributable to our Electricity segment for the year ended December 31, 2016 were $436.3 million, compared to $375.9 million for the year ended December 31, 2015, representing a 16.1% increase from the prior period. This increase was primarily attributable to: (i) the commencement of operations of the second phase of the McGinness Hills and Don A. Campbell power plants in Nevada in February 2015 and September 2015, respectively, as well as the commencement of operations of our Plant 4 at the Olkaria III complex in Kenya in January 2016; (ii) higher energy rates under the Heber 1 PPA commencing in December 2015, and (iii) the consolidation of our Bouillante power plant in Guadeloupe, effective July 5, 2016, following the acquisition of an approximately 60% equity interest in GB. The increase was partially offset by a reduction in revenues generated by some of our power plants due to lower oil and natural gas prices.

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Power generation in our power plants increased by 11.6% from 4,835,109 MWh in the year ended December 31, 2015 to 5,396,959 MWh in the year ended December 31, 2016, mainly due to commencement of commercial operation of the second phase of the McGinness Hills power plant and Don A. Campbell power plant in Nevada, and the commencement of operations of our Plant 4 at the Olkaria III complex in Kenya, as discussed above.

Product Segment

Revenues attributable to our Product segment for the year ended December 31, 2016 were $226.3 million, compared to $218.7 million for the year ended December 31, 2015, which represented a 3.5% increase. The increase in our Product segment revenues was primarily due to the start of revenue recognition from a new geothermal project we build. We recognized approximately $58 million of revenue from this project in the year ended December 31, 2016, compared to approximately $34 million in the year ended December 31, 2015. The total contract price for the project is approximately $99.0 million and it is scheduled to be completed in the first half of 2017. The increase was partially offset by a net decrease of approximately $11 million in revenues from projects we build in Turkey, of which some were completed in the year ended December 31, 2015, and due to timing of revenue recognition and different product mix.

Total Cost of Revenues

Total cost of revenues for the year ended December 31, 2016 was $391.8 million, compared to $376.4 million for the year ended December 31, 2015, representing a 4.1% increase from the prior period. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2016 decreased to 59.1%, compared to 63.3% for the year ended December 31, 2015. 

Electricity Segment

Total cost of revenues attributable to our Electricity segment for the year ended December 31, 2016 was $261.6 million, compared to $242.6 million for the year ended December 31, 2015, representing a 7.8% increase from the prior period. This increase was primarily due to: (i) additional cost of revenues from the second phase of the McGinness Hills and Don A. Campbell power plants, the commencement of operations of our Plant 4 at the Olkaria III complex, and the consolidation of our Bouillante power plant all discussed above; and (ii) reimbursement of $2.5 million of mining tax imposed on us based on an audit performed by the state of Nevada for the years ended December 31, 2008, 2009 and 2010 following our successful appeal of the audit decision in the first quarter of 2015. As a percentage of total Electricity segment revenues, the total cost of revenues attributable to our Electricity segment for the year ended December 31, 2016 was 60.0%, compared to 64.5% for the year ended December 31, 2015. This decrease was primarily due to higher efficiency in some of our operating power plants as well as lower costs of operating the three new power plants mentioned above.

Product Segment

Total cost of revenues attributable to our Product segment for the year ended December 31, 2016 was $130.2 million, compared to $133.8 million for the year ended December 31, 2015, representing a 2.6% decrease from the prior period. This decrease was primarily attributable to efficiencies, cost savings and project management, offset partially due to the increase in Product segment revenues as discussed above. As a percentage of total Product segment revenues, our total cost of revenues attributable to the Product segment for the year ended December 31, 2016 was 57.5%, compared to 61.2% for the year ended December 31, 2015. This decrease was mainly attributable to improvements made at our manufacturing facility and our project management and construction costs as well as the different product mix and different margins in the various sales contracts we entered into for this segment during these periods. 

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Research and Development Expenses

Research and development expenses for the year ended December 31, 2016 were $2.8 million, compared to $1.8 million for the year ended December 31, 2015.

Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2016 were $16.4 million, compared to $16.1 million for the year ended December 31, 2015. Selling and marketing expenses for the year ended December 31, 2016 constituted 2.5% of total revenues for such year, compared to 2.7% of such revenues for the year ended December 31, 2015.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2016 were $46.7 million, compared to $34.8 million for the year ended December 31, 2015.

This increase was mainly due to $11.0 million expenses related to a settlement with certain former employees of the company to settle claims brought by such employees against the company under qui tam provisions of the False Claims Act, partially offset by $3.8 million of expenses related to the share exchange with Ormat Industries, recorded in the first quarter of 2015. General and admisitrative expenses excluding the one-time costs and the costs related to the share exchange, constituted 5.5% and 5.2% of total revenues for the years ended December 31, 2016 and 2015, respectively.

Write-off of Unsuccessful Exploration Activities

Write-off of unsuccessful exploration activities for the year ended December 31, 2016 was $3.0 million compared to $1.6 million for the year ended December 31, 2015. The majority of the write-off of unsuccessful exploration activities for the year ended December 31, 2016, represented the costs related to the Twilight site in Oregon and concession in Chile, which we determined would not support commercial operations. The majority of the write-off of unsuccessful exploration activities for the year ended December 31, 2015 represented the costs related to the Maui prospect in Hawaii, which we determined in the fourth quarter of 2015 would not support commercial operations.

Operating Income

Operating income for the year ended December 31, 2016 was $201.9 million, compared to $164.1 million for the year ended December 31, 2015, representing a 23.1% increase from the prior period. The increase in operating income was primarily attributable to the increase in our gross margin in both our Electricity and Product segments primarily due to the increase in revenues, as discussed above, partially offset by $11.0 million one-time expenses related to a settlement with certain former employees of the company of a claims brought by such employees against the company under qui tam provisions of the False Claim Act. Operating income attributable to our Electricity segment for the year ended December 31, 2016 was $126.8 million, compared to $99.3 million for the year ended December 31, 2015. Operating income attributable to our Product segment for the year ended December 31, 2016 was $75.1 million, compared to $64.7 million for the year ended December 31, 2015.

Interest Expense, Net

Interest expense, net, for the year ended December 31, 2016 was $67.4 million, compared to $72.6 million for the year ended December 31, 2015, representing a 7.1% decrease from the prior period. This decrease was primarily due to: (i) the repayment, in September 2016, of the senior unsecured bonds in the amount of $250 million which bore interest at a fixed rate of 7% per annum, by issuance of new series of senior unsecured bonds in the amounts of $67 million and $137 million, respectively and bear interest at a fixed rate of 3.7% and 4.45% per annum, respectively, as discussed below; (ii) a lower interest expense as a result of principal payments of long term debt and revolving credit lines with banks; partially offset due to $0.8 million decrease related to interest capitalized to projects.

Derivatives and Foreign Currency Transaction Losses

Derivatives and foreign currency transaction losses for the year ended December 31, 2016 were $5.5 million, compared to $1.6 million for the year ended December 31, 2015. Derivatives and foreign currency transaction losses for the year ended December 31, 2016 were attributable primarily to $2.6 million in losses from future contracts to reduce our economic exposure to fluctuations in prices of natural gas and oil under our SO#4 and Puna PPAs, which were not accounted for as hedge transactions, and $1.5 million losses due to changes in the fair value of the contract obligation in the Guadeloupe transaction. Derivatives and foreign currency transaction losses for the year ended December 31, 2015 were attributable primarily to losses on foreign currency forward contracts, which were not accounted for as hedge transactions.

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Income Attributable to Sale of Tax Benefits

Income attributable to the sale of tax benefits to institutional equity investors (as described below under “OPC Transaction” and “ORTP Transaction”) for the year ended December 31, 2016 was $16.5 million, compared to $25.4 million for the year ended December 31, 2015. This income represents mainly the value of PTCs and taxable income or loss generated by ORTP and allocated to investors. This decrease was primarily attributable to a lower taxable loss in ORTP.

Other non-operating income (loss)

Other non-operating loss for the year ended December 31, 2016 was $5.4 million, compared to $2.0 million in the year ended December 31, 2015. Other non-operating loss for the year ended December 31, 2016 includes: (i) prepayment fees of approximately $5.0 million due to the repayment of the senior unsecured bonds in September 2016, as discussed below; and (ii) a make whole premium of $0.6 million resulting from the repurchase of $6.8 million aggregate principal amount of our OFC Senior Secured Notes. Other non-operating loss for the year ended December 31, 2015 includes a capital loss of $1.7 million resulting from the repurchase of $30.6 million aggregate principal amount of our OFC Senior Secured Notes.

Income from operations, before income taxes and equity in income of investees

Income from operations, before income taxes and equity in income of investees for the year ended December 31, 2016 was $141.1 million, compared to $113.6 million for the year ended December 31, 2015, representing a 24.2% increase from the prior period. The income is attributable in total to our foreign operations. The increase compared to the year ending December 31, 2015 was driven by the increase in Product Segment revenues in Indonesia and Chile. The small loss in our domestic operations resulted mainly from the $11.0 million one-time expenses related to a settlement with certain former employees of the company of a claims brought by such employees against the company under qui tam provisions of the False Claim Act and the approximately $5.0 million due to the repayment of the senior unsecured bonds in September 2016.

 Income Taxes

Income tax provision for the year ended December 31, 2016 was $31.8 million, compared to income tax benefit of $15.3 million for the year ended December 31, 2015. Income tax benefit for the year ended December 31, 2015 includes a $49.4 million deferred tax asset relating to the release of the valuation allowance for the additional 50% investment deduction for our Olkaria 3 power plant based on amendments to the Kenya Income Tax Act that came into effect on September 11, 2015 and which extended the period to utilize such investment deduction from five years to ten years. Income tax provision for the year ended December 31, 2015, excluding the $49.4 million, was $34.1 million. The increase in income tax provision from $34.1 million, excluding the $49.4 million, in the year ended December 31, 2015 to $36.5 million, exceluding $4.7 million of tax benefit pertaining to our operations in Kenya (see note 19) in the year ended December 31, 2016, primarily resulted from the increase in income before taxes in jurisdictions outside the U.S. Our effective tax rate for the years ended December 31, 2016, and 2015, excluding the $49.4 million, was 22.5% and 28.8%, respectively. Our effective tax rate is principally based upon the composition of the income in different countries and changes related to valuation allowances for certain countries. Our aggregate effective tax rate is lower than the 35% U.S federal statutory tax rate as a substantial portion of our income is derived in Israel which is taxed at the corporate tax rate of 16%, partially offset by taxes on earnings in Kenya which are taxed at statutory rate of 37.5%. There is no impact on the Company’s income tax expense (benefit) related to the U.S. earnings (losses) due to the offsetting impact on the provision related to the change in the valuation allowance on the Company’s U.S. net deferred tax asset position.

For the year ended December 31, 2016 and 2015, we recorded a valuation allowance in the amount of approximately $109.6 million and $70.5 million respectively, against our U.S. deferred tax assets related to net operating loss (NOL) carryforwards and unutilized tax credits (PTCs and ITCs). As of December 31, 2016 we had U.S. federal NOLs in the amount of approximately $299.6 million, state NOLs in the amount of approximately $244.7 million, and unutilized tax credits of approximately $83.8 million, all of which can be carried forward for 20 years. The related deferred tax assets totaled approximately $109.6 million. Realization of these deferred tax assets and tax credits is dependent on generating sufficient taxable income in the U.S. prior to expiration of the NOL carryforwards and tax credits. The scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies were considered in determining the amount of valuation allowance. A valuation allowance in the amount of $109.6 million was recorded against the U.S. deferred tax assets as of December 31, 2016 because we believe it is more likely than not that the deferred tax assets will not be realized. If sufficient additional evidence of our ability to generate taxable income is established, we may be required to reduce or fully release the valuation allowance, resulting in income tax benefits in our consolidated statement of operations.

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Equity in losses of investees, net

Equity in losses of investees, net in the year ended December 31, 2016 was $7.7 million, compared to $5.5 million in the year ended December 31, 2015. Equity in losses of investees, net derived from our 12.75% share in the losses of the Sarulla project and from profits elimination.

Net Income

Net income for the year ended December 31, 2016 was $101.5 million, compared to $123.3 million for the year ended December 31, 2015, representing a decrease of $21.8 million from the prior period. This decrease in net income was primarily attributable to $11.0 million in one-time general and administrative expenses related to the settlement paid in connection with the FCA claim, as discussed above, the $47.1 million increase in income tax provision, a decrease of $8.9 million in income attributable to sale of tax benefits, and $3.4 million increase in other non-operating loss, partially offset by an increase of $53.3 million in gross margin and a decrease in interest expense of $5.2 million, all as discussed above.

Comparison of the Year Ended December 31, 2015 and the Year Ended December 31, 2014

Total Revenues

Total revenues for the year ended December 31, 2015 were $594.6 million, compared to $559.5 million for the year ended December 31, 2014, representing a 6.3% from the prior period. This increase was attributable to our Product segment, in which revenues increased by 23.4% compared to the corresponding period in 2014. This increase was partially offset by a 1.7% decrease in our Electricity segment revenues over the corresponding period in 2014.

Electricity Segment

Revenues attributable to our Electricity segment for the year ended December 31, 2015 were $436.3 million, compared to $375.9 million for the year ended December 31, 2014, representing a 1.7% decrease from the prior period. This decrease was primarily attributable to a $30 million reduction in revenues generated by some of our power plants due to lower oil and natural gas prices as well as our Puna power plant having lower generation due to a hurricane. This decrease was partially offset by the commencement of operations of the second phase of the McGinness Hills and and Don A. Campbell power plant in Nevada in February 2015 and September 2015, respectively.

Power generation in our power plants increased by 8.6% from 4,450,910 MWh in the year ended December 31, 2014 to 4,835,109 MWh in the year ended December 31, 2015, mainly due to commencement of commercial operation of the second phase of the McGinness Hills power plant and Don A. Campbell power plant, partially offset by the decrease in generation of the Puna and North Brawley power plants.

Product Segment

Revenues attributable to our Product segment for the year ended December 31, 2015 were $218.7 million, compared to $177.2 million for the year ended December 31, 2014, which represented a 23.4% increase. This increase in our Product segment revenues was primarily due to timing of revenue recognition, different product mix and commencing revenue recognition for new contracts.

Total Cost of Revenues

Total cost of revenues for the year ended December 31, 2015 was $376.4 million, compared to $355.8 million for the year ended December 31, 2014, representing a 5.8% increase from the prior period. This increase was primarily due to the increase in cost of revenues from our Product segment, partially offset by a decrease in cost of revenues from our Electricity segment. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2015 decreased to 63.3%, compared to 63.6% for the year ended December 31, 2014. This decrease was attributable to a decrease in cost of revenues as a percentage of total revenues, in both our Electricity and Product segments.

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Electricity Segment

Total cost of revenues attributable to our Electricity segment for the year ended December 31, 2015 was $242.6 million, compared to $246.6 million for the year ended December 31, 2014, representing a 1.6% decrease from the prior period. This decrease was primarily due to: (i) reimbursement of $2.5 million of mining tax imposed on us based on an audit performed by the state of Nevada for the years ended December 31, 2008, 2009 and 2010 following our successful appeal of the audit decision in the first quarter of 2015 and (ii) the fact that in the year ended December 31, 2015 we did not incur costs that we incurred in the year ended December 31, 2014 to address the North Brawley power plant uncontrolled well flow. This decrease in our electricity cost of revenues was partially offset by additional cost of revenues from the second phase of the McGinness Hills power plant and Don A. Campbell power plant that commenced commercial operation in February 2015 and September 2015, respectively, as discussed above. As a percentage of total Electricity segment revenues, the total cost of revenues attributable to our Electricity segment for the year ended December 31, 2015 was 64.5%, compared to 64.5% for the year ended December 31, 2014.

Product Segment

Total cost of revenues attributable to our Product segment for the year ended December 31, 2015 was $133.8 million, compared to $109.1 million for the year ended December 31, 2014, representing a 22.5% increase from the prior period. This increase was primarily attributable to the increase in Product segment revenues as discussed above. As a percentage of total Product segment revenues, our total cost of revenues attributable to the Product segment for the year ended December 31, 2015 was 61.2%, compared to 61.6% for the year ended December 31, 2014. This decrease was mainly attributable to the different product mix and different margins in the various sales contracts we entered into for this segment during these periods, as well as improvements made at our manufacturing plant.

Research and Development Expenses

Research and development expenses for the year ended December 31, 2015 were $1.8 million, compared to $0.8 million for the year ended December 31, 2014. Research and development expenses are net of grants from the DOE in the amount of $0 and $0.5 million for the years ended December 31, 2015 and 2014, respectively, related to the EGS.

Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2015 were $16.1 million, compared to $15.4 million for the year ended December 31, 2014. This increase was primarily due to higher sales commissions related to our Product segment due to higher revenues and different commissions mix. Selling and marketing expenses for the year ended December 31, 2015 constituted 2.7% of total revenues for such year, compared to 2.8% of such revenues for the year ended December 31, 2014.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2015 were $34.8 million, compared to $28.6 million for the year ended December 31, 2014.

This increase was mainly due to $3.8 million of expenses related to the share exchange with Ormat Industries completed in 2015. General and administrative expenses for the year ended December 31, 2015, excluding the costs related to the share exchange, constituted 5.2% and 5.1% of total revenues for the years ended December 31, 2015 and 2014, respectively.

Write-off of Unsuccessful Exploration Activities

Write-off of unsuccessful exploration activities for the year ended December 31, 2015 was $1.6 million compared to $15.4 million for the year ended December 31, 2014. The majority of the write-off of unsuccessful exploration activities for the year ended December 31, 2015 represented the costs related to the Maui prospect in Hawaii, which we determined in the fourth quarter of 2015 would not support commercial operations. Write-off of unsuccessful exploration activities for the year ended December 31, 2014 represented the costs of $8.1 million related to our exploration activities in the Wister site in California, and $7.3 million related to our exploration activities in the Mount Spurr site in Alaska, which we determined in the second and the fourth quarters of 2014, respectively, would not support commercial operations.

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Operating Income

Operating income for the year ended December 31, 2015 was $164.1 million, compared to $143.5 million for the year ended December 31, 2014, representing a 14.4% increase from the prior period. This increase was primarily attributable to the write-off of unsuccessful exploration activities in the amount of $15.4 million for the year ended December 31, 2014 and to an increase in our gross margin in our Product segment, as discussed above. The increase was partially offset by costs associated with the share exchange, as discussed above. Operating income attributable to our Electricity segment for the year ended December 31, 2015 was $99.3 million, compared to $90.4 million for the year ended December 31, 2014. This increase was primarily attributable to a decrease in write-off of unsuccessful exploration activities in the amount of $13.9 million, as described above. Operating income attributable to our Product segment for the year ended December 31, 2015 was $64.7 million, compared to $53.1 million for the year ended December 31, 2014.

Interest Expense, Net

Interest expense, net, for the year ended December 31, 2015 was $72.6 million, compared to $84.7 million for the year ended December 31, 2014, representing a 14.3% decrease from the prior period. This decrease was primarily due to: (i) lower interest expense as a result of principal payments of long term debt and revolving credit lines with banks; (ii) a $2.8 million decrease in interest related to the sale of tax benefits; and (iii) $0.9 million increase related to interest capitalized to projects. The decrease was partially offset by an increase in interest expense related to a loan in the amount of $140.0 million received under the OFC 2 Senior Secured Notes to finance the construction of the second phase of the McGinness Hills power plant in August 2014.

Foreign Currency Translation and Transaction Losses

Foreign currency translations and transaction losses for the year ended December 31, 2015 were $1.6 million, compared to $5.8 million for the year ended December 31, 2014. Foreign currency translations and transaction losses were attributable primarily to losses on foreign currency forward contracts which were not accounted for as hedge transactions.

Income Attributable to Sale of Tax Benefits

Income attributable to the sale of tax benefits to institutional equity investors (as described below under “OPC Transaction” and “ORTP Transaction”) for the year ended December 31, 2015 was $25.4 million, compared to $24.1 million for the year ended December 31, 2014. This income primarily represents the value of PTCs and taxable income or loss generated by OPC and ORTP and allocated to investors in the amount of $5.3 million and $20.1 million, respectively, in the year ended December 31, 2015, compared to $7.0 million and $17.1 million, respectively, in the year ended December 31, 2014. This increase was primarily attributable to a higher taxable loss in ORTP, partially offset by lower depreciation for tax purposes in OPC as a result of declining depreciation rates under MACRS.

Gain from Sale of Property, Plant and Equipment

There was no gain from the sale of property, plant and equipment for the year ended December 31, 2015. Gain from the sale of property, plant and equipment for the year ended December 31, 2014 was $7.6 million. This gain relates to the sale of the Heber Solar project in Imperial County, California for an aggregate purchase price of $35.25 million in the first quarter of 2014. We received the first payment of $15.0 million in the first quarter of 2014, and the second payment of the remaining $20.25 million in the second quarter of 2014. We recognized the gain in the second quarter of 2014.

Other non-operating income (loss)

Other non-operating loss for the year ended December 31, 2015 was $2.0 million, compared to non-operating income of $0.8 million for the year ended December 31, 2014. Other non-operating loss for the year ended December 31, 2015 includes a capital loss of $1.7 million resulting from the repurchase of $30.6 million aggregate principal amount of the OFC Senior Secured Notes.

Income from operations, before income taxes and equity in income of investees

Income from operations, before income taxes and equity in income of investees for the year ended December 31, 2015 was $113.6 million, compared to $85.8 million for the year ended December 31, 2014, representing a 32.4% increase from the prior period. The income is attributable in total to our foreign operations. The increase compared to the year ending December 31, 2014 was driven by the increase in Product Segment revenues in Indonesia and Chile. The small loss in our domestic operations resulted mainly from the low commodity prices in 2015 and the fact that 18.1% of our domestic revenues are linked to commodity prices.

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 Income Taxes

Income tax benefit for the year ended December 31, 2015 was $15.3 million, compared to income tax provision of $27.6 million for the year ended December 31, 2014. Income tax benefit for the year ended December 31, 2015 includes a $49.4 million deferred tax asset relating to the release of the valuation allowance for the additional 50% investment deduction for our Olkaria 3 power plant based on amendments to the Kenya Income Tax Act that came into effect on September 11, 2015 and which extended the period to utilize such investment deduction from five years to ten years. Income tax provision for the year ended December 31, 2015, excluding the $49.4 million deferred tax asset, was $34.1 million, compared to $27.6 million for the year ended December 31, 2014. This increase in income tax provision primarily resulted from the increase in income before taxes in jurisdictions outside the U.S. Our effective tax rate for the years ended December 31, 2015, excluding the $49.4 million deferred tax asset, and 2014, was 28.8% and 32.2%, respectively. The effective tax rate differs from the federal statutory rate of 35% for the year ended December 31, 2015 primarily due to losses in the U.S. and certain foreign jurisdictions.

For the year ended December 31, 2015 and 2014, we recorded a valuation allowance in the amount of approximately $70.5 million and $111.3 million respectively, against our U.S. deferred tax assets in respect of net operating loss (NOL) carryforwards and unutilized tax credits (PTCs and ITCs). As of December 31, 2015 we had U.S. federal NOLs in the amount of approximately $261.0 million, state NOLs in the amount of approximately $191.0 million, and unutilized tax credits of approximately $72.0 million, all of which can be carried forward for 20 years. The related deferred tax assets totaled approximately $70.5 million. Realization of these deferred tax assets and tax credits is dependent on generating sufficient taxable income in the U.S. prior to expiration of the NOL carryforwards and tax credits. The scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies were considered in determining the amount of valuation allowance. A valuation allowance in the amount of $70.5 million was recorded against the U.S. deferred tax assets as of December 31, 2015 as at that point in time, we believed it was more likely than not that the deferred tax assets will not be realized.

Equity in losses of investees, net

Equity in losses of investees, net in the year ended December 31, 2015 was $5.5 million, compared to $3.2 million in the year ended December 31, 2014. Equity in losses of investees, net derived from our 12.75% share in the losses of the Sarulla project and from profits elimination.

Net Income

Net income for the year ended December 31, 2015 was $123.3 million, compared to $55.0 million for the year ended December 31, 2014, representing an increase of $68.3 million, or 124.2% from the prior period. This increase in net income was primarily attributable to the deferred tax asset in Kenya and related expenses for $48.7 million, the $20.6 million in operating income and a decrease in interest expense of $12.1 million, as discussed above. The increase was partially offset by a $7.6 million gain from the sale of property, plant and equipment for the year ended December 31, 2014, as discussed above.

Liquidity and Capital Resources

Our principal sources of liquidity have been derived from cash flows from operations, proceeds from third party debt in the form of borrowings under credit facilities and private offerings, issuances of notes, project financing, tax monetization transactions, short term borrowing under our lines of credit, sale of membership interests in one or more of our projects and cash grants we received under the ARRA. We have utilized this cash to develop and construct power generation plants, fund our acquisitions, pay down existing outstanding indebtedness, and meet our other cash and liquidity needs.

As of December 31, 2016, we had access to the following sources of funds: (i) $230.2 million in cash, cash equivalents of which $215.9 million held by our foreign subsidiaries; and (ii) $139.8 million of unused corporate borrowing capacity under existing lines of credit with different commercial banks.

Our estimated capital needs for 2017 includes approximately $255.0 million for capital expenditures on new projects under development or construction, exploration activity, and operating projects, as well as $66.0 million for debt repayment.

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We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) positive cash flows from our operations; and (iii) future project financing and refinancing (including construction loans). Management believes that based on current stage of implementation of the new strategic plan, the sources of liquidity and capital resources described above will address our anticipated liquidity, capital expenditures, and other investment requirements.

We believe that based on our plans to increase our operations outside of the U.S., the cash generated from our operations outside of the U.S. will be reinvested outside of the U.S. In addition, our U.S. sources of cash and liquidity are sufficient to meet our needs in the U.S., and accordingly, we do not currently plan to repatriate the funds we have designated as being permanently invested outside the U.S. If we change our plans, we may be required to accrue and pay U.S. taxes to repatriate these funds.

Third-Party Debt

Our third-party debt is composed of two principal categories. The first category consists of project finance debt or acquisition financing that we or our subsidiaries have incurred for the purpose of developing and constructing, refinancing or acquiring our various projects, which are described below under “Non-Recourse and Limited-Recourse Third-Party Debt”. The second category consists of debt incurred by us or our subsidiaries for general corporate purposes, which are described below under “Full-Recourse Third-Party Debt.”

Non-Recourse and Limited-Recourse Third-Party Debt

OFC Senior Secured Notes — Non-Recourse

In February 2004, OFC, one of our subsidiaries, issued $190.0 million of OFC Senior Secured Notes for the purpose of refinancing the acquisition cost of the Brady, Ormesa and Steamboat 1, 1A, 2 and 3 power plants, and the financing of the acquisition cost of 50% of the Mammoth complex. The OFC Senior Secured Notes have a final maturity date of December 30, 2020. Principal and interest on the OFC Senior Secured Notes are payable in semi-annual payments. The OFC Senior Secured Notes are collateralized by substantially all of the assets of OFC and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC. There are various restrictive covenants under the OFC Senior Secured Notes, which include limitations on additional indebtedness of OFC and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OFC.  In addition, there are restrictions on the ability of OFC to make distributions to its shareholders, which include a required historical and projected 12-month debt service coverage ratio (DSCR) of not less than 1.25 (measured semi-annually as of June 30 and December 31 of each year). If OFC fails to comply with the DSCR ratio it will be prohibited from making distributions to its shareholders.  We are only required to measure these covenants on a semi-annual basis and as of December 31, 2016, the last measurement date, the actual historical 12-month DSCR was 1.25 and the pro-forma 12-month DSCR was 1.38 (on a semi-annual basis and as of December 31, 2015). There was $17.0 million aggregate principal amount of OFC Senior Secured Notes outstanding as of December 31, 2016.

In June 2015, we repurchased from OFC noteholders $30.6 million of the aggregate principal amount of our OFC Senior Secured Notes, which resulted in approximately $2.5 million savings in interest expense. We recognized a loss of approximately $1.7 million in the year ended December 31, 2015, as a result of the repurchase.

In September 2016, we repurchased from OFC noteholders $6.8 million of the aggregate principal amount of our OFC Senior Secured Notes.We recognized a loss of approximately $0.6 million in the year ended December 31, 2016, as a result of the repurchase.

OrCal Geothermal Senior Secured Notes — Non-Recourse

In December, 2005, OrCal, one of our subsidiaries, issued $165.0 million of OrCal Senior Secured Notes for the purpose of refinancing the acquisition cost of the Heber complex. The OrCal Senior Secured Notes have been rated BBB- by Fitch Ratings. The OrCal Senior Secured Notes have a final maturity date of December 30, 2020. Principal and interest on the OrCal Senior Secured Notes are payable in semi-annual payments. The OrCal Senior Secured Notes are collateralized by substantially all of the assets of OrCal and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OrCal. There are various restrictive covenants under the OrCal Senior Secured Notes which include limitations on additional indebtedness of OrCal and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OrCal. In addition, there are restrictions on the ability of OrCal to make distributions to its shareholders, which include a required historical and projected 12-month DSCR of not less than 1.25 (measured semi-annually as of June 30 and December 31 of each year). If OrCal fails to comply with the DSCR ratio it will be prohibited from making distributions to its shareholders.  We are only required to measure these covenants on a semi-annual basis and as of June, 2016 (the last measurement date of the covenants)the actual historical 12-month DSCR was 1.77, and the pro-forma 12-months DSCR was 2.57. There was $35.2 million aggregate principal amount of OrCal Senior Secured Notes outstanding as of December 31, 2016.

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OFC 2 Senior Secured Notes — Limited Recourse

In September 2011, OFC 2, one of our subsidiaries, and its wholly owned project subsidiaries (collectively, the OFC 2 Issuers) entered into a note purchase agreement (the Note Purchase Agreement) with OFC 2 Noteholder Trust, as purchaser, John Hancock, as administrative agent, and the DOE, as guarantor, in connection with the offer and sale of up to $350.0 million aggregate principal amount of OFC 2 Senior Secured Notes due December 31, 2034.

Subject to the fulfillment of customary and other specified conditions precedent, the OFC 2 Senior Secured Notes may be issued in up to six distinct series associated with the phased construction (Phase I and Phase II) of the Jersey Valley, McGinness Hills and Tuscarora geothermal power plants, which are owned by the OFC 2 Issuers. The OFC 2 Senior Secured Notes will mature and the principal amount of the OFC 2 Senior Secured Notes will be payable in equal quarterly installments and in any event not later than December 31, 2034. Each series of notes will bear interest at a rate calculated based on a spread over the U.S. Treasury yield curve that will be set at least ten business days prior to the issuance of such series of notes. Interest will be payable quarterly in arrears. The DOE guarantees payment of 80% of principal and interest on the OFC 2 Senior Secured Notes pursuant to Section 1705 of Title XVII of the Energy Policy Act of 2005, as amended. The conditions precedent to the issuance of the OFC 2 Senior Secured Notes include certain specified conditions required by the DOE in connection with its guarantee of the OFC 2 Senior Secured Notes.

In October 2011, the OFC 2 Issuers completed the sale of $151.7 million aggregate principal amount of 4.687% Series A Notes due 2032 (the Series A Notes). The net proceeds from the sale of the Series A Notes, after deducting transaction fees and expenses, were approximately $141.1 million, and were used to finance a portion of the construction costs of Phase I of the McGinness Hills and Tuscarora power plants and to fund certain reserves. Principal and interest on the Series A Notes are payable quarterly in arrears on the last day of March, June, September and December of each year.

On June 20, 2014, Phase I of the Tuscarora facility achieved project completion under the OFC 2 Note Purchase Agreement. In accordance with the terms of the Note Purchase Agreement, we recalibrated the original financing assumptions and as a result the loan amount was adjusted through a principal payment of $4.3 million.

On August 29, 2014, OFC 2 signed a $140.0 million loan under the OFC 2 Notes to finance the construction of the McGinness Hills Phase 2 project. This draw is the last tranche (Series C notes) under the Note Purchase Agreement with John Hancock Life Insurance Company (USA) and is guaranteed by the U.S. DOE Loan Programs Office in accordance with and subject to the DOE’s Loan Guarantee Program under section 1705 of Title XVII of the Energy Policy Act of 2005. The $140.0 million loan, which matures in December 2032, carries a 4.61% coupon with principal to be repaid on a quarterly basis. The OFC 2 Notes, which include loans for the Tuscarora, Jersey Valley and McGinness Hills complexes, are rated “BBB” by Standard & Poor’s.

In connection with the drawdown, on August 13, 2014, we entered into an on-the-run interest lock agreement with a financial institution with a termination date of of August 15, 2014. This on-the-run interest lock agreement had a notional amount of $140.0 million and was designated by us as a cash flow hedge. The objective of this cash flow hedge was to eliminate the variability in the change in the 10-year U.S. Treasury rate as that is one of the components in the annual interest rate of OFC 2 loan that was forecasted to be fixed on August 15, 2014. As such, we hedged the variability in total proceeds attributable to changes in the 10-year U.S. Treasury rate for the forecasted issuance of fixed rate OFC 2 loan. On the settlement date of August 18, 2014, we paid $1.5 million to the counterparty of the on-the-run interest rate lock agreement.

The OFC 2 Senior Secured Notes are collateralized by substantially all of the assets of OFC 2 and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC 2. There are various restrictive covenants under the OFC 2 Senior Secured Notes, which include limitations on additional indebtedness of OFC 2 and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OFC 2. In addition, there are restrictions on the ability of OFC 2 to make distributions to its shareholders.

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Among other things, the distribution restrictions include a historical debt service coverage ratio requirement of at least 1.2 (on a blended basis for all OFC 2 power plants), measured, at the time of any proposed distribution, over each of the two six-months periods comprised of distinct consecutive fiscal quarters immediately preceding the proposed distribution, and a projected future debt service coverage ratio requirement of at least 1.5 (on a blended basis for all OFC 2 power plants), measured, at the time of any proposed distribution, over each of the two six-months periods comprised of distinct consecutive fiscal quarters immediately following such proposed distribution. As of December 31, 2016, our historical debt service coverage ratio was 2.49 and 2.09, respectively for each of the two six-month periods, and our projected future debt service coverage ratio was 1.98 and 2.05, respectively for each of the two six-month periods.

There were $247.2 million and $262.0 million of OFC 2 senior secured Notes outstanding as of December 31, 2016 and December 31, 2015.

We provided a guarantee in connection with the issuance of the Series A and C Notes, which will be available to be drawn upon if certain trigger events occur. The trigger event is any loss, liability, damage, expense or cost to the Jersey Valley facility caused by the interconnection under the various interconnection related agreements of the Dixie Meadows (Phase 2) project that we may develop in the future.

Olkaria III Finance Agreement with OPIC — Limited Recourse

In August  2012, OrPower 4, one of our subsidiaries, entered into a finance agreement with OPIC, an agency of the U.S. government, to provide limited-recourse senior secured debt financing in an aggregate principal amount of up to $310.0 million (the OPIC Loan) for the refinancing and financing of our Olkaria III geothermal power complex in Kenya. The finance agreement was amended on November 9, 2012.

The OPIC Loan is comprised of three tranches:

• Tranche I in an aggregate principal amount of $85.0 million, which was drawn in November 2012, was used to prepay approximately $20.5 million (plus associated prepayment penalty and breakage costs of $1.5 million) of the DEG Loan, as described below under “Full Recourse Debt”. The remainder of Tranche I proceeds was used for reimbursement of prior capital costs and other corporate purposes.

• Tranche II in an aggregate principal amount of $180.0 million was used to fund the construction and well field drilling for Plant 2 of the Olkaria III geothermal power complex. In November 2012, an amount of $135.0 million was disbursed under this Tranche II, and in February 2013, the remaining $45.0 million was distributed under this Tranche II.

• Tranche III in an aggregate principal amount of $45.0 million was used to fund the construction of Plant 3 of the Olkaria III geothermal power complex and was drawn down in full in November 2013.

In July 2013, we completed the conversion of the interest rate applicable to both Tranche I and Tranche II from a floating interest rate to a fixed interest rate. The average fixed interest rate for Tranche I, which has an outstanding balance of $66.0 million and matures on December 15, 2030 and Tranche II, which has an outstanding balance of $142.9 million and matures on June 15, 2030, is 6.31%. In November 2013, we fixed the interest rate applicable to Tranche III. The fixed interest rate for Tranche III, which has an outstanding balance of $37.6 million and matures on December 15, 2030, is 6.12%.

OrPower 4 has a right to make voluntary prepayments of all or a portion of the OPIC Loan subject to prior notice, minimum prepayment amounts, and a prepayment premium of 2% in the first two years after the Plant 2 commercial operation date, declining to 1% in the third year after the Plant 2 commercial operation date, and without premium thereafter, plus a redemption premium. In addition, the OPIC Loan is subject to customary mandatory prepayment in the event of certain reductions in generation capacity of the power plants, unless such reductions will not cause the projected ratio of cash flow to debt service to fall below 1.7.

The OPIC Loan is secured by substantially all of OrPower 4’s assets and by a pledge of all of the equity interests in OrPower 4.

The finance agreement includes customary events of default, including failure to pay any principal, interest or other amounts when due, failure to comply with covenants, breach of representations and warranties, non-payment or acceleration of other debt of OrPower 4, bankruptcy of OrPower 4 or certain of its affiliates, judgments rendered against OrPower 4, expropriation, change of control, and revocation or early termination of security documents or certain project-related agreements, subject to various exceptions and notice, cure and grace periods.

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The repayment of the remaining outstanding DEG Loan (see “Full-Recourse Third-Party Debt” below) in the amount of approximately $15.8 million as of December 31, 2016, has been subordinated to the OPIC Loan.

There are various restrictive covenants under the OPIC Loan, which include a required historical and projected 12-month DSCR of not less than 1.4 (measured as of March 15, June 15, September 15 and December 15 of each year).  If OrPower 4 fails to comply with these financial ratios it will be prohibited from making distributions to its shareholders.  In addition, if the DSCR falls below 1.1, subject to certain cure rights such failure will constitute an event of default by OrPower 4. This covenant in respect of Tranche I became effective on December 15, 2014. As of December 31, 2016, the actual historical and projected 12-month DSCR was 2.69 and 2.96, respectively.

As of December 31, 2016, $246.6 million of the OPIC Loan was outstanding.

Amatitlan Financing — Limited Recourse

On July 31, 2015, one of our indirect wholly-owned subsidiaries, Ortitlản, Limitada, obtained a 12-year secured term loan in the principal amount of $42.0 million for the 20 MW Amatitlan power plant in Guatemala. Under the credit agreement with Banco Industrial S.A. and Westrust Bank (International) Limited, we can expand the Amatitlan power plant with financing to be provided either via equity, additional debt from Banco Industrial S.A. or from other lenders, subject to certain limitations on expansion financing in the credit agreement.

The loan is payable in 48 quarterly payments commencing September 30, 2015. The loan bears interest at a rate per annum equal to the sum of the LIBO Rate (which cannot be lower than 1.25%) plus a margin of (i) 4.35% as long as the Company’s guaranty of the loan (as described below) is outstanding or (ii) 4.75% otherwise. Interest is payable quarterly, on March 30, June 30, September 30 and December 30 of each year, on the stated maturity date of the loan and on any prepayment or payment of the loan. The loan must be prepaid upon the occurrence of certain events, such as casualty, condemnation, asset sales and expansion financing not provided by the lenders under the credit agreement, among others. The loan may be voluntarily prepaid if certain conditions are satisfied, including payment of a premium (ranging from 100-50 basis points) if prepayment occurs prior to the eighth anniversary of the loan.

There are various restrictive covenants under the Amatitlan credit agreement. These include, among others, (i) a financial covenant to maintain a Debt Service Coverage Ratio (as defined in the credit agreement) of not less than 1.15 to 1.00 as of the last day of any fiscal quarter and (ii) limitations on Restricted Payments (as defined in the credit agreement) that among other things would limit dividends that could be paid to us unless the historical and projected Debt Service Coverage Ratio is not less than 1.25 to 1.00 for the four fiscal quarterly periods (calculated as a single accounting period). As of December 31, 2016, the actual historical and projected 12-month Debt Service Coverage Ratio was 1.87 and 1.92, respectively. The credit agreement includes various events of default that would permit acceleration of the loan (subject in some cases to grace and cure periods). These include, among others, a Change of Control (as defined in the credit agreement) and failure to maintain certain required balances in debt service and maintenance reserve accounts. The credit agreement includes certain equity cure rights for failure to maintain the Debt Service Coverage Ratio and the minimum amounts required in the debt service and maintenance reserve accounts.

The loan is secured by substantially all the assets of the borrower and a pledge of all of the membership interests of the borrower.

The Company has guaranteed payment of all obligations under the credit agreement and related financing documents. The guaranty is limited in the sense that the Company is only required to pay the guaranteed obligations if a “trigger event” occurs. A trigger event is the occurrence and continuation of a default by INDE in its payment obligations under the power purchase agreement for the Amatitlàn power plant or a refusal by INDE to receive capacity and energy sold under that power purchase agreement. Our obligations under the guaranty may be terminated prior to payment in full of the guaranteed obligations under certain circumstances described in the guaranty. If our guaranty is terminated early, the interest rate payable on the loan would increase as described above.

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As of December 31, 2016, $36.8 million of this loan is outstanding.

Don A. Campbell Senior Secured Notes — Non-Recourse

On November 29, 2016, ORNI 47 LLC (“ORNI 47”) entered into a note purchase agreement (the “Note Purchase Agreement”) with MUFG Union Bank, N.A., as collateral agent, Munich Reinsurance America, Inc. and Munich American Reassurance Company (the “Purchasers”) pursuant to which ORNI 47 issued and sold to the Purchasers $92.5 million aggregate principal amount of its 4.03% Senior Secured Notes due September 27, 2033 (the “Notes”) in a private placement exempt from the registration requirements of the Securities Act of 1933, as amended. ORNI 47 is the owner of the Don A. Campbell Phase I (“DAC 1”) geothermal power plant, and part of ORPD.

The net proceeds to ORNI 47 from the sale of the Notes, after deducting certain transaction expenses and the funding of a debt service reserve account, were approximately $87.1 million and ORNI 47 intends to use the proceeds from the sale of the Notes to refinance the development and construction costs of the DAC 1 geothermal power plant, which were originally financed using equity.

ORNI 47 will pay a scheduled amount of principal of the Notes beginning on December 27, 2016 and then quarterly, on the 27th day of each March, June, September and December, until the Notes mature.

The Notes constitute senior secured obligations of ORNI 47 and are secured by all of the assets of ORNI 47. Under the Note Purchase Agreement, ORNI 47 may prepay at any time all, or from time to time any part of, the Notes in an amount equal to at least $2 million or such lesser amount as may remain outstanding under the Notes at 100% of the principal amount to be prepaid plus the applicable make-whole amount determined for the prepayment date with respect to such principal amount. Upon the occurrence of a Change of Control (as defined in the Note Purchase Agreement), ORNI 47 must make an offer to each holder of Notes to repurchase all of the holder’s Notes at 101% of the aggregate principal amount of Notes to be repurchased plus accrued and unpaid interest, if any, on the Notes to be repurchased to, but not including, the date of repurchase. Each holder of Notes may accept such offer in whole or in part. In certain events, including certain asset sales outside the ordinary course of business, ORNI 47 must make mandatory prepayments of the Notes at 100% of the principal amount to be prepaid. The Note Purchase Agreement requires ORNI 47 to comply with certain covenants, including, among others, restrictions on the incurrence of indebtedness or liens, amendment or modification of material project documents, the ability of ORNI 47 to merge or consolidate with another entity. The Note Purchase Agreement also contains customary events of default.  In addition, there are restrictions on the ability of ORNI 47 to make distributions to its shareholders, which include a required historical and projected Debt Service Coverage Ratio not less than 1.20 for the four fiscal quarterly periods. As of December 31, 2016, the projected Debt Service Coverage Ratio was 1.85.

As of December 31, 2016, $92.4 million is outstanding under the DAC 1 Loan.

Full-Recourse Third-Party Debt

Credit Agreements

Union Bank. In February 2012, Ormat Nevada, our wholly owned subsidiary, entered into an amended and restated credit agreement with Union Bank. Under the credit agreement as amended and restated and further amended through the date of this report, the credit termination date is June 30, 2017. On December 31, 2016, the aggregate amount available under the credit agreement was increased by $10 million to $60.0 million. The facility is limited to the issuance, extension, modification or amendment of letters of credit. Union Bank is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as parties thereto. In connection with this transaction, we entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which we agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured.

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There are various restrictive covenants under the credit agreement, including a requirement for Ormat Nevada to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) 12-month DSCR of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of December 31, 2016: (i) the actual 12-month debt to EBITDA ratio was 2.95; (ii) the 12-month DSCR was 2.54; and (iii) the distribution leverage ratio was 0.81. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of Union Bank.

As of December 31, 2016, letters of credit in the aggregate amount of $32.6 million remain issued and outstanding under this committed credit agreement with Union Bank.

HSBC. In May 2013, Ormat Nevada entered into a credit agreement with HSBC Bank USA, N.A for one year with annual renewals. The current expiration date of the facility under this credit agreement is December 31, 2017. The aggregate amount available under the credit agreement was increased by $10 million to $35.0 million. This credit line is limited to the issuance, extension, modification or amendment of letters of credit and $10.0 million out of this credit line is available to be drawn for working capital needs. HSBC is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as parties thereto. In connection with this transaction, we entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which we agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured.

There are various restrictive covenants under the credit agreement, including a requirement to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) 12-month DSCR of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of December 31, 2016: (i) the actual 12-month debt to EBITDA ratio was 2.95; (ii) the 12-month DSCR was 2.54; and (iii) the distribution leverage ratio was 0.81. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of HSBC.

As of December 31, 2016, letters of credit in the aggregate amount of $23.2 million remain issued and outstanding under this committed credit agreement.

Other Banks. We also have committed credit agreements with five other commercial banks for an aggregate amount of $429.8 million. Under the terms of these credit agreements, we or our Israeli subsidiary, Ormat Systems, can request: (i) extensions of credit in the form of loans and/or the issuance of one or more letters of credit in the amount of up to $215.0 million; and (ii) the issuance of one or more letters of credit in the amount of up to $214.8 million. The credit agreements mature at the end of March 2017 and July 2019. Loans and draws under the credit agreements or under any letters of credit will bear interest at the respective bank’s cost of funds plus a margin. As of December 31, 2016, there was no outstanding loan balance.

As of December 31, 2016, letters of credit with an aggregate stated amount of $285.7 million were issued and outstanding under these credit agreements.

Letters of Credits under the Credit Agreements

Some of our customers require our project subsidiaries to post letters of credit in order to guarantee their respective performance under relevant contracts. We are also required to post letters of credit to secure our obligations under various leases and licenses and may, from time to time, decide to post letters of credit in lieu of cash deposits in reserve accounts under certain financing arrangements. In addition, our subsidiary, Ormat Systems is required from time to time to post performance letters of credit in favor of our customers with respect to orders of products.

As of December 31, 2016, committed letters of credit in the aggregate amount of $341.6 million remained issued and outstanding under the credit agreements with Union Bank, HSBC and five of the commercial banks as described under “Credit Agreements”.

Term Loans. We have a $20.0 million term loan with a group of institutional investors, which matures on August 1, 2017, is payable in 12 semi-annual installments commencing February 1, 2012, and bears interest at 6-month LIBOR plus 5.0%. As of December 31, 2016, $3.3 million was outstanding under this loan.

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Senior Unsecured Bonds. We had an aggregate principal amount of approximately $250.0 million of Senior Unsecured Bonds issued and outstanding. We issued approximately $142.0 million aggregate principal amount of these bonds in August 2010 and an additional $107.5 million aggregate principal amount in February 2011. Subject to early redemption, the principal of the bond was repayable in a single bullet payment upon the final maturity of the bonds on August 1, 2017. The bonds bore interest at a fixed rate of 7.00%, payable semi-annually. The bonds that we issued in February 2011 were issued at a premium which reflects an effective fixed interest rate of 6.75%.

In September 2016, the Company concluded an auction tender and accepted subscriptions for $204 million aggregate principal amount of two tranches (Series 2 approximately $67 million and Series 3 approximately $137 million) of senior unsecured bonds. The proceeds from the senior unsecured bonds were used on September 29, 2016, to prepay the Company’s $250 million senior secured bonds that were payable on August 1, 2017.

The senior unsecured bonds, which were issued on September 14, 2016, have an outstanding aggregate principal amount of approximately $204.0 million consisting of two tranches (approximately $67 million principal amount of Series 2 and approximately $137 million principal amount of Series 3). The Series 2 Bonds will mature in September 2020 and bear interest at a fixed rate of 3.7% per annum, payable semi-annually. The Series 3 Bonds will mature in September 2022 and bear interest at a fixed rate of 4.45% per annum, payable semi-annually. The Bonds will be repaid at maturity in a single bullet payment, unless earlier prepaid by Ormat pursuant to the terms and conditions of the trust instrument that governs the Bonds. Both tranches received a rating of ilA+ from Maloot S&P in Israel with a stable outlook.

Loan Agreements with DEG (The Olkaria III Complex). OrPower 4 entered into a project financing loan to refinance its investment in Plant 1 of the Olkaria III complex located in Kenya with a group of European DFIs arranged by DEG. The DEG Loan will mature on December 15, 2018, and is payable in 19 equal semi-annual installments. Interest on the loan is variable based on 6-month LIBOR plus 4.0%. We fixed the interest rate on most of the loan at 6.90%. As of December 31, 2016, $15.8 million is outstanding under the DEG Loan (out of which $10.8 million bears interest at a fixed rate).

In October 2012, OrPower 4, DEG and the other parties thereto amended and restated the DEG Loan Agreement. The amendment became effective on November 9, 2012 upon the execution by OrPower 4 of the Tranche I and Tranche II Notes under the OPIC loan and the related disbursements of the proceeds thereof under the OPIC Finance Agreement (as described above under the heading “Non-Recourse and Limited –Recourse Third-Party Debt”). As part of the amendment we prepaid in full two loans under the DEG facility in the total principal amount of approximately $20.5 million. The amended and restated DEG Loan Agreement provides for (i) the release and discharge of all collateral security previously provided by OrPower 4 to the secured parties under the DEG Loan Agreement and the substitution of the Company’s guarantee of OrPower 4’s payment and certain other performance obligations in lieu thereof; (ii) the establishment of a LIBOR floor of 1.25% in respect of one of the loans under the DEG Loan Agreement, and (iii) the elimination of most of the affirmative and negative covenants under the DEG Loan Agreement and certain other conforming provisions as a result of OrPower 4’s execution of the OPIC Finance Agreement and its obligations thereunder.

On October 20, 2016, OrPower 4 entered into a new $50 million subordinated facility agreement with DEG (the “DEG 2 Facility Agreement”) and on December 21, 2016, OrPower 4 completed a drawdown of the full loan amount of $50 million, with a fixed interest rate of 6.28% for the duration of the loan (the “DEG 2 Loan”). The DEG 2 Loan will be repaid in 20 equal semi-annual principal installments commencing December 21, 2018, with a final maturity on June 21, 2028. The DEG 2 Loan is intended for the refinance of Plant 4 of the Olkaria III Complex, which was originally financed using equity and is subordinated to the senior loan provided by OPIC for Plants 1-3 of the complex. The loan is guaranteed by the Company.

Under the DEG 2 Facility Agreement, OrPower 4 may prepay at any time all, or from time to time any part of the DEG 2 Loan in an amount equal to at least $5 million or such lesser amount as may remain outstanding under the DEG 2 Loan at 100% of the principal amount to be prepaid plus the applicable make-whole amount and certain prepayment premium amount determined for the prepayment date with respect to such principal amount. In certain events, OrPower 4 must make mandatory prepayments of the DEG 2 Loan at 100% of the principal amount to be prepaid plus the applicable make-whole amount and certain prepayment premium amount determined for the prepayment date with respect to such principal amount. The DEG 2 Facility Agreement requires OrPower 4 to comply with certain covenants, including, among others, restrictions on the incurrence of indebtedness or liens. The Facility Agreement also contains customary events of default.

As of December 31, 2016, $50.0 million is outstanding under the DEG 2 Loan.

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Restrictive covenants

Our obligations under the credit agreements, the loan agreements, and the trust instrument governing the bonds described above, are unsecured, but we are subject to a negative pledge in favor of the banks and the other lenders and certain other restrictive covenants. These include, among other things, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of our assets, or a change of control in our ownership structure. Some of the credit agreements, the term loan agreements, and the trust instrument contain cross-default provisions with respect to other material indebtedness owed by us to any third party. In some cases, we have agreed to maintain certain financial ratios, which are measured quarterly, such as: (i) equity of at least $600 million and in no event less than 25% of total assets; (ii) 12-month debt, net of cash, cash equivalents, and short-term bank deposits to Adjusted EBITDA ratio not to exceed 6.0; and (iii) dividend distributions not to exceed 35% of net income in any calendar year. As of December 31, 2016: (i) total equity was $1,170.0 million and the actual equity to total assets ratio was 47.53% and (ii) the 12-month debt, net of cash, cash equivalents, to Adjusted EBITDA ratio was 2.32. During the year ended December 31, 2016, we distributed interim dividends in an aggregate amount of $25.7 million. The failure to perform or observe any of the covenants set forth in such agreements, subject to various cure periods, would result in the occurrence of an event of default and would enable the lenders to accelerate all amounts due under each such agreement.

As described above, we are currently in compliance with our covenants with respect to the credit agreements, the loan agreements and the trust instrument, and believe that the restrictive covenants, financial ratios and other terms of any of our (or Ormat Systems’) full-recourse bank credit agreements will not materially impact our business plan or operations.

Future minimum payments

Future minimum payments under long-term obligations, excluding revolving credit lines with commercial banks and lease payments under the Puna lease transaction described below, as of December 31, 2016, are as follows:

	(Dollars in thousands)
Year ending December 31:
2017	$	65,971
2018		64,805
2019		59,146
2020		126,870
2021		46,579
Thereafter		593,161
Total	$	956,532

Puna Power Plant Lease Transactions

In May 2005, our Hawaiian subsidiary, PGV, entered into a transaction involving the original geothermal power plant of the Puna complex located on the Big Island (the Puna Power Plant).

Pursuant to a 31-year head lease (the Head Lease), PGV leased the Puna Power Plant to an unrelated lessor (the Puna lessor) in return for prepaid lease payments in the total amount of $83.0 million. The carrying value of the leased assets as of September 30, 2016 amounted to $28.7 million, net of accumulated depreciation of $32.2 million. The Puna Lessor simultaneously leased back the Puna Power Plant to PGV under a 23-year lease (the Project Lease). PGV’s rent obligations under the Project Lease will be paid solely from revenues generated by the Puna Power Plant under a PPA that PGV has with HELCO. The Head Lease and the Project Lease are non-recourse lease obligations to the Company. PGV’s rights in the geothermal resource and the related PPA have not been leased to the Puna Lessor as part of the Head Lease but are part of the Puna Lessor’s security package.

The transaction was concluded with financing parties by means of a leveraged lease transaction. A secondary stage of the lease transaction relating to two new geothermal wells that PGV drilled in the second half of 2005 (for production and injection) was completed on December 30, 2005. Pursuant to a 31-year head lease, PGV leased its geothermal power plant to the abovementioned financing parties in return for payments of $83.0 million by such financing parties to PGV, which are accounted for as deferred lease income.

There are various restrictive covenants under the lease agreement, including a requirement to have certain reserve funds that need to be managed by the indenture trustee in accordance with certain balance requirements. Such reserve funds amounted to $2.9 million and $2.1 million as of December 31, 2016 and December 31, 2015, respectively, and were included in restricted cash accounts in the consolidated balance sheets and were classified as current as they were used for current payments.

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Opal Transaction

On December 19, 2016, Ormat Nevada entered into an equity contribution agreement (the “Equity Contribution Agreement”) with OrLeaf LLC (“OrLeaf”) and JPM Capital Corporation (“JPM”) with respect to Opal Geo LLC (“Opal Geo”). Also on December 16, 2016, OrLeaf, a newly formed limited liability company formed by Ormat Nevada and ORPD LLC, entered into an amended and restated limited liability company agreement of Opal Geo (the “LLC Agreement”) with JPM. The transactions contemplated by the Equity Contribution Agreement and LLC Agreement will allow the Company to monetize federal production tax credits (“PTCs”) and certain other tax benefits relating to the operation of five geothermal power plants located in Nevada.

In connection with the transactions contemplated by the Equity Contribution Agreement and the LLC Agreement, Ormat Nevada transferred its indirect ownership interest in the McGinness Hills (Phase I and Phase II), Tuscarora, Jersey Valley and Don A. Campbell Phase 2 (“DAC 2”) geothermal power plants to Opal Geo. Prior to such transfer, Ormat Nevada held an approximately 63.25% indirect ownership interest in DAC 2 through ORPD LLC, a joint venture between Ormat Nevada and Northleaf Geothermal Holdings LLC (“Northleaf”), an affiliate of Northleaf Capital Partners, and held, directly or indirectly, a 100% ownership interest in the remaining geothermal power plants that were transferred to Opal Geo.

Pursuant to the Equity Contribution Agreement, JPM contributed approximately $62.1 million to Opal Geo in exchange for 100% of the Class B Membership Interests of Opal Geo. JPM also agreed to make deferred capital contributions to Opal Geo based on the amount of electricity generated by the DAC 2 and McGinness Hills Phase II power plants which are eligible for the federal production tax credit. The Company expects the aggregate amount of JPM’s deferred capital contributions to equal approximately $21 million and to be paid over time covering the period through December 31, 2022.

Under the LLC Agreement, until December 31, 2022, OrLeaf will receive distributions of 97.5% of any distributable cash generated by operation of the power plants while JPM will receive distributions of 2.5% of any distributable cash generated by operation of the power plants. Unless JPM has already achieved its target internal rate of return on its investment in Opal Geo, from December 31, 2022 until JPM has achieved its target internal rate of return, JPM will receive 100% of any distributable cash generated by operation of the power plants. Thereafter, OrLeaf will receive distributions of 97.5%, and JPM will receive 2.5%, of any distributable cash generated by operation of the power plants.

Under the LLC Agreement, all items of Opal Geo income and loss, gain, deduction and credit (including the federal PTCs relating to the operation of the two PTC eligible power plants) will be allocated, until JPM has achieved its target internal rate of return on its investment in Opal Geo (and for so long as the two PTC eligible power plants are generating PTCs), 99% to JPM and 1% to OrLeaf, or 5% to JPM and 95% to OrLeaf if PTCs are no longer available to either of the two PTC eligible power plants. Once JPM achieves its target internal rate of return, all items of Opal Geo income and loss, gain, deduction and credit will be allocated 5% to JPM and 95% to OrLeaf.

Under the LLC Agreement, OrLeaf, which owns 100% of the Class A Membership Interests in Opal Geo, will serve as the managing member of Opal Geo and control the day-to-day management of Opal Geo and its portfolio of five power plants. However, in certain limited circumstances (such as bankruptcy of Orleaf, fraud or gross negligence by OrLeaf) JPM may remove OrLeaf as the managing member of Opal Geo. JPM, as the Class B Member of Opal Geo, has consent and approval rights with respect to certain items that are designated as major decisions for Opal Geo and the five power plants. In addition, by virtue of certain provisions in OrLeaf’s own limited liability company agreement, and consistent with the ORPD LLC formation documents, Northleaf has similar consent and approval rights with respect to OrLeaf’s determination of major decisions pertaining to the DAC 2 power plant. In both cases, these major decisions are generally equivalent to customary minority protection rights. As a result, the Company’s wholly owned subsidiary, Ormat Nevada, which serves as the managing member of OrLeaf and as the managing member of ORPD LLC, will effectively retain the day-to-day control and management of Opal Geo and its portfolio of five power plants.

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The LLC Agreement contains certain customary restrictions on transfer applicable to both OrLeaf and JPM with respect to their respective Membership Interests in Opal Geo, and also provides OrLeaf with a right of first offer in the event JPM desires to transfer any of its Class B Membership Interests, pursuant to which OrLeaf may purchase such Class B Membership Interests. The LLC Agreement also provides OrLeaf with the option to purchase all of the Class B Membership Interests on either December 31, 2022 or the date that is 9 years after the closing date under the Equity Contribution Agreement at a price equal to the greater of (i) the fair market value of the Class B Membership Interests as of the date of purchase (subject to certain adjustments) and (ii) $3 million.

Pursuant to the Equity Contribution Agreement, the Company has provided a guaranty for the benefit of JPM of certain of OrLeaf’s indemnification obligations to JPM under the LLC Agreement. In addition, Ormat Nevada also provided a guaranty for the benefit of JPM of all present and future payment and performance obligations of OrLeaf under the LLC Agreement and each ancillary document to which OrLeaf is a party.

Pursuant to the Equity Contribution Agreement, JPM contributed approximately $62.1 million to Opal Geo in exchange for 100% of the Class B Membership Interests of Opal Geo. The contribution was recorded as a $3.7 million allocation to noncontrolling interests and a $58.5 million allocation to liabilities associated with sale of tax benefits as described in Note 1. JPM also agreed to make deferred capital contributions to Opal Geo based on the amount of electricity generated by the DAC 2 and McGinness Hills Phase II power plants which are eligible for the federal production tax credit. The Company expects the aggregate amount of JPM's deferred capital contributions to equal approximately $21 million and to be paid over time covering the period through December 31, 2022.

OPC Transaction

In June 2007, Ormat Nevada entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. (Morgan Stanley Geothermal LLC and Lehman-OPC LLC, respectively), under which those investors purchased, for cash, interests in a newly formed subsidiary of Ormat Nevada, OPC, entitling the investors to certain tax benefits (such as PTCs and accelerated depreciation) and distributable cash associated with four geothermal power plants in Nevada.

The first closing under the agreements occurred in 2007 and covered our Desert Peak 2, Steamboat Hills, and Galena 2 power plants. The investors paid $71.8 million at the first closing. The second closing under the agreements occurred in 2008 and covered the Galena 3 power plant. The investors paid $63.0 million at the second closing.

Ormat Nevada continues to operate and maintain the power plants. Under the agreements, Ormat Nevada initially received all of the distributable cash flow generated by the power plants, while the investors received substantially all of the PTCs and the taxable income or loss (together, the Economic Benefits). Once Ormat Nevada recovered the capital that it invested in the power plants, which occurred in the fourth quarter of 2010, the investors began receiving both the distributable cash flow and the Economic Benefits. Once the investors reach a target after-tax yield on their investment in OPC (the OPC Flip Date), Ormat Nevada will receive 95% of both distributable cash and taxable income, on a going forward basis. Following the OPC Flip Date, Ormat Nevada also has the option to purchase the investors’ remaining interest in OPC at the then-current fair market value or, if greater, the investors’ capital account balances in OPC. If Ormat Nevada were to exercise this purchase option, it would become the sole owner of the power plants again.

Our voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. Through Ormat Nevada, we own all of the Class A membership units, which represent 75% of the voting rights in OPC and the investors(as described below) own all of the Class B membership units, which represent 25% of the voting rights of OPC. Other than in respect of customary protective rights, all operational decisions in OPC are decided by the vote of a majority of the membership units. Following the OPC Flip Date, Ormat Nevada’s voting rights will increase to 95% and the investor’s voting rights will decrease to 5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the OPC Flip Date and therefore consolidates OPC.We expect the Flip Date to occur in the second quarter of 2017.

The Class B membership units have a 5% residual economic interest in OPC, which commences as of the OPC Flip Date. This residual 5% interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments. The Class B membership units are currently held by Morgan Stanley Geothermal LLC and JPM. On October 30, 2009, Ormat Nevada acquired from Lehman-OPC LLC all of the Class B membership units of OPC held by Lehman-OPC LLC pursuant to a right of first offer for a purchase price of $18.5 million in cash and on February 3, 2011, Ormat Nevada sold to JPM all of the Class B membership units of OPC that it had acquired for a sale price of $24.9 million in cash.

ORTP Transaction

On January 24, 2013, Ormat Nevada entered into agreements with JPM under which JPM purchased interests in a newly formed subsidiary of Ormat Nevada, ORTP, entitling JPM to certain tax benefits (such as PTCs and accelerated depreciation) associated with certain geothermal power plants in California and Nevada.

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Under the terms of the transaction, Ormat Nevada transferred the Heber complex, the Mammoth complex, the Ormesa complex, and the Steamboat 2 and 3, Burdette (Galena 1) and Brady power plants to ORTP, and sold Class B membership units in ORTP to JPM. In connection with the closing, JPM paid approximately $35.7 million to Ormat Nevada and will make additional payments to Ormat Nevada of 25% of the value of PTCs generated by the portfolio over time. The additional payments were expected to be made until December 31, 2016 and total up to a maximum amount of $11.0 million, of which we received $1.5 million, $2.0 million, $1.7 million and $2.2 million in the first quarters of 2017 , 2016, 2015 and 2014, respectively.

Ormat Nevada will continue to operate and maintain the power plants. Under the agreements, Ormat Nevada will initially receive all of the distributable cash flow generated by the power plants, while JPM will receive substantially all the Economic Benefits. JPM’s return is limited by the terms of the transaction. Once JPM reaches a target after-tax yield on its investment in ORTP (the ORTP Flip Date), Ormat Nevada will receive 97.5% of the distributable cash and 95.0% of the taxable income, on a going forward basis. At any time during the twelve-month period after the end of the fiscal year in which the ORTP Flip Date occurs (but no earlier than the expiration of five years following the date that the last of the power plants was placed in service for purposes of federal income taxes), Ormat Nevada also has the option to purchase JPM’s remaining interest in ORTP at the then-current fair market value. If Ormat Nevada were to exercise this purchase option, it would become the sole owner of the power plants again.

The Class B membership units entitle the holder to a 5.0% (allocation of income and loss) and 2.5% (allocation of cash) residual economic interest in ORTP. The 5.0% and 2.5% residual interest commences on achievement by JPM of a contractually stipulated return that triggers the ORTP Flip Date, which occurred on December 31, 2016. This residual 5.0% and 2.5% interest represents noncontrolling interests and are not subject to mandatory redemption or guaranteed payments. We expect to buy out the Class B membership units for $2.0 million in the second quarter of 2017.

Our voting rights in ORTP are based on a capital structure that is comprised of Class A and Class B membership units. Through Ormat Nevada, we own all of the Class A membership units, which represent 75.0% of the voting rights in ORTP. JPM owns all of the Class B membership units, which represent 25.0% of the voting rights of ORTP. Other than in respect of customary protective rights, all operational decisions in ORTP are decided by the vote of a majority of the membership units. Ormat Nevada retains the controlling voting interest in ORTP both before and after the ORTP Flip Date and therefore will continue to consolidate ORTP.

Liquidity Impact of Uncertain Tax Positions

As discussed in Note 19 to our consolidated financial statements set forth in Item 8 of this annual report, we have a liability associated with unrecognized tax benefits and related interest and penalties in the amount of approximately $5.7 million as of December 31, 2016. This liability is included in long-term liabilities in our consolidated balance sheet, because we generally do not anticipate that settlement of the liability will require payment of cash within the next twelve months. We are not able to reasonably estimate when we will make any cash payments required to settle this liability.

Dividend

The following are the dividends declared by us during the past two years:

Date Declared	Dividend Amount per Share		Record Date	Payment Date
February 24, 2015	$	0.08	March 16, 2015	March 27, 2015
May 6, 2015	$	0.06	May 19, 2015	May 27, 2015
August 3, 2015	$	0.06	August 18, 2015	September 2, 2015
November 3, 2015	$	0.06	November 18, 2015	December 2, 2015
February 23, 2016	$	0.31	March 15, 2016	March 29, 2016
May 4, 2016	$	0.07	May 18, 2016	May 24, 2016
August 2, 2016	$	0.07	August 16, 2016	August 30, 2016
November 7, 2016	$	0.07	November 21, 2016	December 6, 2016
February 28, 2017	$	0.17	March 15, 2017	March 29, 2017

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Historical Cash Flows

The following table sets forth the components of our cash flows for the relevant periods indicated:

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Net cash provided by operating activities	$	159,285		$	190,025		$	213,235
Net cash used in investing activities		(158,531	)		(90,971	)		(129,162	)
Net cash provided by (used in) financing activities		43,541			46,635			(101,197	)
Net change in cash and cash equivalents		44,295			145,689			(17,124	)

For the Year Ended December 31, 2016

Net cash provided by operating activities for the year ended December 31, 2016 was $159.3 million, compared to $190.0 million for the year ended December 31, 2015. This decrease of $30.7 million resulted primarily from (i) an increase in receivables of $33.3 million in the year ended December 31, 2016, compared to a $3.8 million in the year ended December 31, 2015, as a result of timing of collections from our customers; and (ii) a decrease in billing in excess of costs and estimated earnings on uncompleted contracts, net of $29.3 million in our Product segment in the year ended December 31, 2016, compared to an increase of $11.8 million in the year ended December 31, 2015, as a result of timing in billing of our customers.

Net cash used in investing activities for the year ended December 31, 2016 was $158.5 million, compared to $91.0 million for the year ended December 31, 2015. The principal factors that affected our net cash used in investing activities during the year ended December 31, 2016 were capital expenditures of $151.9 million, primarily for our facilities under construction, and $20.1 million net cash paid for the acquisition of GB, reduced by a net decrease of $15.2 million in restricted cash and cash equivalents, due to timing of debt repayments.

Net cash provided by financing activities for the year ended December 31, 2016 was $43.5 million, compared to $46.6 million used for the year ended December 31, 2015. The principal factors that affected the net cash provided by financing activities during the year ended December 31, 2016 were: (i) $203.5 million net proceeds from issuance of two new series of Senior Unsecured Bonds; (ii) net proceeds from issuance of shares to a noncontrolling interest in the amount of $44.1 million; (iii) $59.9 million of net proceed from the OPAL Transaction; (iv) $92.5 million of proceeds from a term loan for our Don A. Campbell power plant and (v) $50.0 million of proceeds from a term loan for our Olkaria 3 Complex plant 4, reduced by: (i) early repayment of $249.5 million of Senior Unsecured Bonds; $6.8 million of cash paid to repurchase our OFC Senior Secured Notes; (ii) the repayment of long-term debt in the amount of $62.1 million; (iii) $63.7 million of cash paid to noncontrolling interests ; and (iv) a $26.0 million cash dividend paid.

For the Year Ended December 31, 2015

Net cash provided by operating activities for the year ended December 31, 2015 was $190.0 million, compared to $213.2 million for the year ended December 31, 2014. This decrease of $23.2 million resulted primarily from (i) an increase in receivables of $3.8 million in the year ended December 31, 2015, compared to a decrease of $47.1 million in the year ended December 31, 2014, as a result of timing of collections from our customers; and (ii) a decrease in deferred income tax liabilities of $39.5 million in the year ended December 31, 2015, mainly due to the deferred tax asset in Kenya, as discussed above, compared to an increase of $13.1 million in the year ended December 31, 2014. The decrease was partially offset by the increase in cash inflow due to higher net income of $68.3 million, up from $55.0 million for the year ended December 31, 2014 to $123.3 million for the year ended December 31, 2015 as described above.

Net cash used in investing activities for the year ended December 31, 2015 was $91.0 million, compared to $129.2 million for the year ended December 31, 2014. The principal factors that affected our net cash used in investing activities during the year ended December 31, 2015 were capital expenditures of $152.1 million, primarily for our facilities under construction, reduced by a net decrease of $43.7 million in restricted cash and cash equivalents, due to timing of debt repayments, and $15.4 million derived from cash of Ormat Industries due to the share exchange.

Net cash provided by financing activities for the year ended December 31, 2015 was $46.6 million, compared to $101.2 million used for the year ended December 31, 2014. The principal factors that affected the net cash provided by financing activities during the year ended December 31, 2015 were: net proceeds from issuance of shares to a noncontrolling interest in the amount of $156.5 million and $42.0 million of proceeds from a term loan for our Amatitlan power plant, reduced by: (i) $30.6 million of cash paid to repurchase our OFC Senior Secured Notes; (ii) the repayment of long-term debt in the amount of $71.7 million; (iii) a net decrease of $20.3 million against our revolving credit lines with commercial banks; (iv) $19.1 million of cash paid to noncontrolling interests; and (v) payment of a $12.7 million cash dividend.

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EBITDA and Adjusted EBITDA

We calculate EBITDA as net income before interest, taxes, depreciation and amortization. We calculate Adjusted EBITDA as net income before interest, taxes, depreciation and amortization, adjusted for (i) termination fees, (ii) impairment of long-lived assets, (iii) write-off of unsuccessful exploration activities, (iv) any mark-to-market gains or losses from accounting for derivatives, (v) merger and acquisition transaction costs (vi) stock-based compensation, (vii) gain or loss from extinguishment of liabilities (viii) gain or loss on sale of subsidiary and property, plant and equipment and (ix) other unusual or non-recurring items. EBITDA and Adjusted EBITDA are not measurements of financial performance or liquidity under accounting principles generally accepted in the United States of America, or U.S. GAAP, and should not be considered as an alternative to cash flow from operating activities or as a measure of liquidity or an alternative to net earnings as indicators of our operating performance or any other measures of performance derived in accordance with U.S. GAAP. EBITDA and Adjusted EBITDA are presented because we believe they are frequently used by securities analysts, investors and other interested parties in the evaluation of a company’s ability to service and/or incur debt. However, other companies in our industry may calculate EBITDA and Adjusted EBITDA differently than we do.

This information should not be considered in isolation from, or as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP or other non-GAAP financial measures.

Adjusted EBITDA for the year ended December 31, 2016 was $323.8 million, compared to $291.3 million for the year ended December 31, 2015 and $272.7 million for the year ended December 31, 2014.

The following table reconciles net cash provided by operating activities to EBITDA and adjusted EBITDA, for the years ended December 31, 2016, 2015, and 2014:

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Net cash provided by operating activities	$	159,285		$	190,025		$	213,235
Adjusted for:
Interest expense, net (excluding amortization of deferred financing costs)		60,553			63,802			76,970
Interest income		(971	)		(297	)		(312	)
Income tax provision (benefit)		31,837			(15,258	)		27,608
Minority interest in earnings of subsidiaries
Adjustments to reconcile net income to net cash provided by operating activities (excluding depreciation and amortization)		48,208			40,530			(57,422	)
EBITDA		298,912			278,802			260,079
Mark-to-market gains or losses from accounting for derivatives		319			1,409			(1,788	)
Stock-based compensation		5,157			3,955			5,571
Gain on sale of subsidiary and property, plant and equipment		(686	)		-			(7,628	)
Termination fee		-			-			-
Impairment of long-lived assets		-			-
Loss from extinguishment of liability		5,780			1,710			-
Merger and acquisition transaction costs		335			3,800			1,000
Settlement expenses		11,000			-			-
Write-off of unsuccessful exploration activities		3,017			1,579			15,439
Adjusted EBITDA	$	323,834		$	291,255		$	272,673
Net cash used in investing activities	$	(158,531	)	$	(90,971	)	$	(129,162	)
Net cash provided by (used in) financing activities	$	43,541		$	46,635		$	(101,197	)

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Capital Expenditures

Our capital expenditures primarily relate to the enhancement of our existing power plants and the exploration, development and construction of new power plants.

We have estimated approximately $406.0 million in capital expenditures for construction of new projects and enhancements to our existing power plants, of which we have invested approximately $165.0 million as of December 31, 2016. We expect to invest $165.0 million in 2017 and the remaining $76.0 million thereafter.

In addition, we estimate approximately $90.0 million in additional capital expenditures in 2017 to be allocated as follows: (i) $25.0 million for development of new projects; (ii) $35.0 million for maintenance capital expenditures to our operating power plants; (iii) $25.0 million for continued exploration activity under various leases for geothermal resources where we have already started exploration activity; and (iv) $5.0 million for enhancements to our production facilities.

In the aggregate, we estimate our total capital expenditures for 2017 to be approximately $255.0 million.

Based on current conditions, we believe that we have sufficient financial resources to fund our activities and execute our business plans. However, the cost of obtaining financing for our project needs may increase significantly or such financing may be difficult to obtain.

Exposure to Market Risks

Based on current conditions, we believe that we have sufficient financial resources to fund our activities and execute our business plans. However, the cost of obtaining financing for our project needs may increase significantly or such financing may be difficult to obtain.

We, like other power plant operators, are exposed to electricity price volatility risk. Our exposure to such market risk is currently limited because many of our long-term PPAs (except for the 25 MW PPA for the Puna complex and the aggregate 90 MW PPAs for the Heber 2 power plant in the Heber complex, the Ormesa complex and the G2 power plant in the Mammoth complex) have fixed or escalating rate provisions that limit our exposure to changes in electricity prices. The energy payments under the PPAs of the Heber 2 power plant in the Heber complex, the Ormesa complex and the G2 power plant in Mammoth complex are determined by reference to the relevant power purchaser’s SRAC. A decline in the price of natural gas will result in a decrease in the incremental cost that the power purchaser avoids by not generating its electrical energy needs from natural gas, or by reducing the price of purchasing its electrical energy needs from natural gas power plants, which in turn will reduce the energy payments that we may charge under the relevant PPA for these power plants. In May 2015 and February 2016, we entered into derivative transactions to reduce our exposure to the price of natural gas under these PPAs, until December 29, 2016. The Puna complex is currently benefiting from energy prices which are higher than the floor under the 25 MW PPA for the Puna complex as a result of the high fuel costs that impact HELCO’s avoided costs.

As of December 31, 2016, 94.6% of our consolidated long-term debt was fixed rate debt and therefore was not subject to interest rate volatility risk. As of such date, 5.4% of our long-term debt was floating rate debt, exposing us to interest rate risk in connection therewith. As of December 31, 2016, $51.4 million of our long-term debt remained subject to some interest rate risk.

We currently maintain our surplus cash in short-term, interest-bearing bank deposits, money market securities and commercial paper (with a minimum investment grade rating of AA by Standard & Poor’s Ratings Services.

Our cash equivalents are subject to interest rate risk. Fixed rate securities may have their market value adversely impacted by a rise in interest rates, while floating rate securities may produce less income than expected if interest rates fall. As a result of these factors, our future investment income may fall short of expectations because of changes in interest rates, or we may suffer losses in principal if we are forced to sell securities that decline in market value because of changes in interest rates.

We are also exposed to foreign currency exchange risk, in particular the fluctuation of the U.S. dollar versus the NIS. Risks attributable to fluctuations in currency exchange rates can arise when we or any of our foreign subsidiaries borrow funds or incur operating or other expenses in one type of currency but receive revenues in another. In such cases, an adverse change in exchange rates can reduce such subsidiary’s ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary, or increase such subsidiary’s overall expenses. Risks attributable to fluctuations in foreign currency exchange rates can also arise when the currency denomination of a particular contract is not the U.S. dollar. Substantially all of our PPAs in the international markets are either U.S. dollar-denominated or linked to the U.S. dollar. Our construction contracts from time to time contemplate costs which are incurred in local currencies. The way we often mitigate such risk is to receive part of the proceeds from the contract in the currency in which the expenses are incurred. Currently, we have forward contracts in place to reduce our foreign currency exposure, and expect to continue to use currency exchange and other derivative instruments to the extent we deem such instruments to be the appropriate tool for managing such exposure. We do not believe that our exchange rate exposure has or will have a material adverse effect on our financial condition, results of operations or cash flows.

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We performed a sensitivity analysis on the fair values of our swap contracts on oil prices, put options on natural gas prices, long-term debt obligations, and foreign currency exchange forward contracts. The swap contracts on oil prices, put options on natural gas prices and foreign currency exchange forward contracts listed below principally relate to trading activities. The sensitivity analysis involved increasing and decreasing forward rates at December 31, 2016 and 2015 by a hypothetical 10% and calculating the resulting change in the fair values.

At this time, the development of our new strategic plan has not exposed us to any additional market risk. However, as the implementation of the plan progresses, we may be exposed to additional or different market risks.

The results of the sensitivity analysis calculations as of December 31, 2016 and 2015 are presented below:

	Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates
	As of December 31,						As of December 31,
Risk	2016			2015			2016			2015		Change in the Fair Value of
	(In thousands)
Foreign Currency	$	(4,665	)	$	(3,894	)	$	4,632		$	4,760	Foreign currency forward contracts
Interest Rate	$	(254	)	$	(408	)	$	260		$	417	Ormat Funding Corp. (“OFC”)
Interest Rate	$	(281	)	$	(646	)	$	284		$	660	Orcal Geothermal Inc. (“OrCal”)
Interest Rate	$	(7,174	)	$	(9,322	)	$	7,496		$	9,941	OFC 2 LLC (“OFC 2”)
Interest Rate	$	(64	)	$	(175	)	$	65		$	172	Loan from DEG
Interest Rate	$	(7,667	)	$	(9,164	)	$	8,039		$	9,685	Loan from OPIC
Interest Rate	$	-	(1)	$	-		$	-	(1)	$	-	Amatitlan loan
Interest Rate	$	(4,351	)	$	(1,888	)	$	4,472		$	1,907	Senior unsecured bonds
Interest Rate	$	(1,568	)	$	-		$	1,639		$	-	New DEG loan ("DEG 2") loan
Interest Rate	$	(2,749	)	$	-		$	2,890		$	-	Don A. Campbell 1 ("DAC 1 ") Senior Secured Notes
Interest Rate	$	(161	)	$	-		$	167		$	-	Other long-term loans

(1) The application of a 10% increase and decrease to the interest rate, did not exceed the minimum rate as set in the loan agreement

Effect of Inflation

We do not expect that inflation will be a significant risk in the near term, given the current global economic conditions, however, that could change in the future. To address rising inflation, some of our contracts include certain provisions that mitigate inflation risk.

In connection with the Electricity segment, inflation may directly impact an expense we incur for the operation of our projects, thereby increasing our overall operating costs. The negative impact of inflation may be partially offset by price adjustments built into some of our PPAs that could be triggered upon such occurrences. The energy payments pursuant to the PPAs for the Brady power plant, the Steamboat 2 and 3 power plants, the Steamboat Hills power plant, and the Burdette power plant increase every year through the end of the relevant terms of such agreements, though such increases are not directly linked to the CPI or any other inflationary index. Lease payments are generally fixed, while royalty payments are generally calculated as a percentage of revenues and therefore are not significantly impacted by inflation. In our Product segment, inflation may directly impact fixed and variable costs incurred in the construction of our power plants, thereby increasing our operating costs in the Product segment. We are more likely to be able to offset all or part of this inflationary impact through our project pricing. With respect to power plants that we build for our own electricity production, inflationary pricing may impact our operating costs which may be partially offset in the pricing of the new long-term PPAs that we negotiate.

128

Contractual Obligations and Commercial Commitments

The following tables set forth our material contractual obligations as of December 31, 2016 (in thousands):

			Payments Due By Period
	Remaining Total		2017		2018		2019		2020		2021		Thereafter
Long-term liabilities principal	$	956,532	$	65,971	$	64,805	$	59,146	$	126,870	$	46,579	$	593,161
Interest on long-term liabilities (1)		314,475		45,592		41,792		38,097		34,692		31,448		122,854
Future minimum operating lease		30,622		8,747		8,944		6,018		2,450		1,723		2,740
Benefits upon retirement (2)		13,679		1,867		2,497		1,655		1,119		1,400		5,141
Asset retirement obligation		23,348		—		—		—		—		—		23,348
Purchase commitments (3)		108,137		108,137		—		—		—		—		—
	$	1,446,793	$	230,314	$	118,038	$	104,916	$	165,131	$	81,150	$	747,244

___________

(1) Interest on the OFC Senior Secured Notes due in 2020 is fixed at a rate of 8.25%. Interest on the OrCal Senior Secured Notes due in 2020 is fixed at a rate of 6.21%. Interest on the OFC 2 Senior Secured Notes Series A due in 2032 is fixed at a rate of 4.687%. Interest on the DAC1 Senior Secured Notes due in 2033 is fixed at a rate of 4.03%. Interest on the OPIC Loan due in 2030 is fixed at an average rate of 6.29%. Interest on the DEG Loan due in 2018 is fixed for $10.8 million as of December 31, 2016, at a rate of 6.9% and variable on the remaining balance (which as of December 31, 2016 was $5.0 million). Interest on the new DEG 2 loan due in 2028 is fixed at a rate of 6.28%. Interest on the senior unsecured bonds due in 2020 is fixed at a rate of 3.7%. Interest on the senior unsecured bonds due in 2022 is fixed at a rate of 4.45%. Interest on the remaining debt is variable (based primarily on changes in LIBOR rates). For purposes of the above calculation of interest payments pertaining to variable rate debt, future LIBOR rates were based on constant maturity swaps.

(2) The above amounts were determined based on the employees’ current salary rates and the number of years’ service that will have been accumulated at their expected retirement date. These amounts do not include amounts that might be paid to employees that will cease working with us before reaching their expected retirement age.

(3) We purchase raw materials for inventories, construction-in-process and services from a variety of vendors. During the normal course of business, in order to manage manufacturing lead times and help assure adequate supply, we enter into agreements with contract manufacturers and suppliers that either allow them to procure goods and services based upon specifications defined by us, or that establish parameters defining our requirements. At December 31, 2016, total obligations related to such supplier agreements were approximately $108.1 million (approximately $51.0 million of which relate to construction-in-process). All such obligations are payable in 2017.

The table above does not reflect unrecognized tax benefits of $5.7 million, the timing of which is uncertain. Refer to Note 19 to our consolidated financial statements set forth in Item 8 of this annual report for additional discussion of unrecognized tax benefits. The above table also does not reflect a liability associated with the sale of tax benefits of $54.7 million, the timing of which is uncertain. Refer to Note 14 to our consolidated financial statements as set forth in Item 8 of this annual report for additional discussion of our liability associated with the sale of tax benefits.

Concentration of Credit Risk

Our credit risk is currently concentrated with the following major customers: Southern California Edison, Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy), KPLC, Southern California Public Power Authority and Hyundai. If any of these customers fails to make payments under its PPAs with us, such failure would have a material adverse impact on our financial condition. Also, by implementing our multi-year strategic plan we may be exposed, by expanding our customer base, to different credit profile customers than our current customers.

Southern California Edison accounted for 5.1%, 9.7%, and 13.5% of our total revenues for the three years ended December 31, 2016, 2015, and 2014, respectively. Southern California Edison is also the power purchaser and revenues source for our Mammoth project, which we accounted for separately under the equity method of accounting through August 1, 2010.

Sierra Pacific Power Company and Nevada Power Company accounted for 19.2%, 19.5%, and 16.5% of our total revenues for the three years ended December 31, 2016, 2015, and 2014, respectively.

129

KPLC accounted for 16.5%, 14.6%, and 15.4% of our total revenues for the three years ended December 31, 2016, 2015, and 2014, respectively.

Southern California Public Power Authority accounted for 10.2%, 5.2% and 3.9% of our total revenues for the three years ended December 31, 2016, 2015 and 2014, respectively.

Hyundai (Sarulla geothermal power project) accounted for 15.2%, 15.7% and 6.8% of our total revenues for the three years ended December 31, 2016, 2015 and 2014, respectively

Tax Benefits

The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies. If we started construction of a new geothermal power plant in the United States by December 31, 2016, we are permitted to claim a tax credit based on the power produced from a geothermal power plant. These production-based credits, which in 2016 were 2.3 cents per kWh, are adjusted annually for inflation and may be claimed for ten years on the electricity produced by the project and sold to third parties after the project is placed in service. In lieu of the production tax credits, we are permitted to claim a tax credit against our U.S. federal income taxes equal to 30% of certain eligible costs when the project is placed in service, so long as the project was under construction by the end of 2016. If the project was not under construction in time, then we are permitted to claim a 10% investment tax credit. The owner of the power plant may not claim both the investment tax credit and the production-based tax credit. New solar projects that are under construction by December 2019 will qualify for a 30% investment tax credit. The credit will fall to 26% for projects starting construction in 2020 and 22% for projects starting construction in 2021. Projects that are under construction before these deadlines must be placed in service by December, 31 2023 to qualify for the higher investment tax credit. Projects placed in service after December, 31, 2023 will only qualify for a 10%investment tax credit. Under current tax rules, any unused tax credit has a one-year carry back and a twenty-year carry forward.

We are also permitted to depreciate, or write off, most of the cost of the plant. In cases where we claim the one-time 30% (or 10%) tax credit, our tax basis in the plant that we can recover through depreciation is reduced by one-half of the tax credit. In cases where we claim the production tax credit, there is no reduction in the tax basis for depreciation. Projects that are placed in service in 2016 and 2017 are eligible for “bonus” depreciation and we will be permitted to write off 50% of the cost of that equipment in the year the power plant is placed in service. Projects placed in service in 2018 would qualify for a 40% bonus and Projects placed in service in 2019 would qualify for a 30% bonus. After applying any depreciation bonus that is available, we can write off the remainder of our tax basis in the plant, if any, over five years on an accelerated basis, meaning that more of the cost may be deducted in the first few years than during the remainder of the depreciation period.

Ormat Systems received “Benefited Enterprise” status under Israel’s Law for Encouragement of Capital Investments, 1959 (the Investment Law), with respect to two of its investment programs through 2011. In January 2011, new legislation amending the Investment Law was enacted. Under the new legislation, a uniform rate of corporate tax will apply to all qualified income of certain industrial companies, as opposed to the previous law’s incentives that are limited to income from a “Benefited Enterprise” during their benefits period. As a result, we now pay a uniform corporate tax rate of 16% with respect to that qualified income.

Ormat Systems tax assessment for fiscal years 2010-2014 was finalized and settled in January 2017. The settlement resulted in no impact to income statement due to release of the related uncertain tax position liability.

As previously reported by the Company, the Kenya Revenue Authority (“KRA”) conducted an audit related to the Company’s operations in Kenya for fiscal years 2012 - 2013. In January 2017, KRA concluded its audit for the subject period and issued a demand letter to the Company for additional tax payments of approximately $16.1 million, including interest and penalties. KRA’s assessment, among other points, rejected the Company's income tax deduction of 150% of its investment in geothermal well drilling during the relevant period, on the basis that such work falls under mining activities (and not geothermal activities) which have a different allowable deduction under the Kenya Income Tax Act. The KRA audit and assessment is not final and is subject to objection by the Company. The Company's operations in Kenya utilize a geothermal resource license from the Ministry of Energy and Petroleum. The Company does not conduct and is not involved in any mining activity under applicable Kenyan law. Therefore, the Company believes that its original tax position was and remains correct under Kenyan tax law and regulations, and has submitted a notice of objection to the KRA which it intends to pursue vigorously. If the KRA position prevails and is applied to subsequent periods, the Company's deferred tax asset of $49.4 million recorded in 2015 may be impacted. At present, the Company has recorded a provision based on its assessment of its reasonably expected potential exposure.

130

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information responding to Item 7A is included in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this annual report.

131

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements of Ormat Technologies, Inc. and Subsidiaries
Report of Independent Registered Public Accounting Firm	133
Consolidated Financial Statements as of December 31, 2016 and 2015 and for Each of the Three Years in the Period Ended December 31, 2016:
Consolidated Balance Sheets	134
Consolidated Statements of Operations and Comprehensive Income (Loss)	135
Consolidated Statements of Equity	136
Consolidated Statements of Cash Flows	137
Notes to Consolidated Financial Statements	138

132

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Ormat Technologies, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations and comprehensive income (loss), equity, and cash flows present fairly, in all material respects, the financial position of Ormat Technologies, Inc. and its 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, the Company maintained, in all material respects, effective internal control over financial reporting 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 (COSO). The Company’s management is responsible for these financial statements, 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 Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed 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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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. Also, 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.

/s/ PricewaterhouseCoopers LLP

San Francisco, California

March 1, 2017

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2016			2015
		(Dollars in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	230,214		$	185,919
Restricted cash and cash equivalents (primarily related to VIEs)		34,262			49,503
Receivables:
Trade		80,807			55,301
Other		17,482			7,885
Inventories		12,000			18,074
Costs and estimated earnings in excess of billings on uncompleted contracts		52,198			25,120
Prepaid expenses and other		45,867			33,334
Total current assets		472,830			375,136
Deposits and other		18,553			17,968
Deferred charges		43,773			42,811
Property, plant and equipment, net ($1,483,224 and $1,481,258 related to VIEs, respectively)		1,556,378			1,559,335
Construction-in-process ($120,853 and $129,165 related to VIEs, respectively)		306,709			248,835
Deferred financing and lease costs, net		3,923			4,022
Intangible assets, net		52,753			25,875
Goodwill		6,650			—
Total assets	$	2,461,569		$	2,273,982
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	91,650		$	91,955
Billings in excess of costs and estimated earnings on uncompleted contracts		31,630			33,892
Current portion of long-term debt:
Limited and non-recourse (primarily related to VIEs):
Senior secured notes		32,234			29,930
Other loans		21,495			21,495
Full recourse		12,242			11,229
Total current liabilities		189,251			188,501
Long-term debt, net of current portion:
Limited and non-recourse (primarily related to VIEs):
Senior secured notes (less deferred financing costs of $9,177 and $10,852, respectively)		350,388			294,476
Other loans (less deferred financing costs of $6,409 and $7,492, respectively)		261,845			275,888
Full recourse:
Senior unsecured bonds (plus unamortized premium based upon 7% of $0 and $513, respectively and less deferred financing costs of $755 and $283, respectively)		203,577			249,698
Other loans (less deferred financing costs of $1,346 and $435, respectively)		57,063			18,687
Accumulated losses of unconsolidated company in excess of investment		11,081			8,100
Liability associated with sale of tax benefits		54,662			11,665
Deferred lease income		54,561			58,099
Deferred income taxes		35,382			32,654
Liability for unrecognized tax benefits		5,738			10,385
Liabilities for severance pay		18,600			19,323
Asset retirement obligation		23,348			20,856
Other long-term liabilities		21,294			1,776
Total liabilities		1,286,790			1,190,108
Commitments and contingencies (Note 23)
Redeemable nonconrolling interest		4,772			--
Equity:
The Company's stockholders' equity:
Common stock, par value $0.001 per share; 200,000,000 shares authorized; 49,667,340 and 49,107,901 shares issued and outstanding as of December 31, 2016 and December 31, 2015, respectively		50			49
Additional paid-in capital		869,463			849,223
Retained earnings		216,644			148,396
Accumulated other comprehensive income (loss)		(7,732	)		(7,667	)
		1,078,425			990,001
Noncontrolling interest		91,582			93,873
Total equity		1,170,007			1,083,874
Total liabilities and equity	$	2,461,569		$	2,273,982

The accompanying notes are an integral part of the consolidated financial statements

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands, except per share data)
Revenues:
Electricity	$	436,292		$	375,920		$	382,301
Product		226,299			218,724			177,223
Total revenues		662,591			594,644			559,524
Cost of revenues:
Electricity		261,573			242,612			246,630
Product		130,223			133,753			109,143
Total cost of revenues		391,796			376,365			355,773
Gross profit		270,795			218,279			203,751
Operating expenses:
Research and development expenses		2,762			1,780			783
Selling and marketing expenses		16,424			16,077			15,425
General and administrative expenses		46,710			34,782			28,614
Write-off of unsuccessful exploration activities		3,017			1,579			15,439
Operating income		201,882			164,061			143,490
Other income (expense):
Interest income		971			297			312
Interest expense, net		(67,389	)		(72,577	)		(84,654	)
Derivatives and foreign currency transaction gains (losses)		(5,534	)		(1,622	)		(5,839	)
Income attributable to sale of tax benefits		16,503			25,431			24,143
Gain from sale of property, plant and equipment		—			—			7,628
Other non-operating income (expense), net		(5,345	)		(1,991	)		756
Income from continuing operations before income taxes and equity in losses of investees		141,088			113,599			85,836
Income tax (provision) benefit		(31,837	)		15,258			(27,608	)
Equity in losses of investees, net		(7,735	)		(5,508	)		(3,213	)
Income from continuing operations		101,516			123,349			55,015
Net income attributable to noncontrolling interest		(7,586	)		(3,776	)		(833	)
Net income attributable to the Company's stockholders	$	93,930		$	119,573		$	54,182
Comprehensive income:
Net income		101,516			123,349			55,015
Other comprehensive income (loss), net of related taxes:
Currency translation adjustments		(1,648	)		—			—
Change in unrealized gains or losses in respect of the Company's share in derivatives instruments of unconsolidated investment		1,185			1,028			(8,112	)
Loss in respect of derivative instruments designated for cash flow hedge		87			91			(902	)
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge		(96	)		(118	)		(141	)
Comprehensive income		101,044			124,350			45,860
Comprehensive income attributable to noncontrolling interest		(7,179	)		(3,776	)		(833	)
Comprehensive income attributable to the Company's stockholders	$	93,865		$	120,574		$	45,027
Earnings per share attributable to the Company's stockholders:
Basic:
Net income	$	1.90		$	2.46		$	1.19
Diluted:
Net income	$	1.87		$	2.43		$	1.18
Weighted average number of shares used in computation of earnings per share attributable to the Company's stockholders:
Basic		49,469			48,562			45,508
Diluted		50,140			49,187			45,859
Dividend per share declared	$	0.52		$	0.26		$	0.21

The accompanying notes are an integral part of the consolidated financial statements.

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

	The Company's Stockholders' Equity
							Retained			Accumulated
					Additional		Earnings			Other
	Common Stock				Paid-in		(Accumulated			Comprehensive						Noncontrolling			Total
	Shares		Amount		Capital		Deficit)			Income (Loss)			Total			Interest			Equity
	(Dollars in thousands, except per share data)
Balance at December 31, 2013		45,461	$	46	$	735,295	$	(3,088	)	$	487		$	732,740		$	12,371		$	745,111
Stock-based compensation		—		—		5,571		—			—			5,571			—			5,571
Exercise of options by employees and directors		76		—		981		—			—			981			—			981
Cash paid to non controlling interest		—		—		—		—			—			—			(651	)		(651	)
Cash dividend declared, $0.21 per share		—		—		—		(9,555	)		—			(9,555	)		—			(9,555	)
Increase in noncontrolling interest in ORTP LLC		—		—		—		—			—			—			257			257
Acquisition of noncontrolling interest in Crump		—		—		159		—			—			159			(987	)		(828	)
Net (loss) income		—		—		—		54,182			—			54,182			833			55,015
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment
Loss in respect of derivative instruments designated for cash flow hedge (net of related tax of $554)		—		—		—		—			(902	)		(902	)		—			(902	)
Change in unrealized gains or losses in respect of the Company's share in derivative instruments of unconsolidated investment (net of related tax of $0)		—		—		—		—			(8,112	)		(8,112	)		—			(8,112	)
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $87)		—		—		—		—			(141	)		(141	)		—			(141	)
Balance at December 31, 2014		45,537	$	46	$	742,006	$	41,539		$	(8,668	)	$	774,923		$	11,823		$	786,746
Stock-based compensation		—		—		3,955		—			—			3,955			—			3,955
Exercise of options by employees and directors		574		—		6,085		—			—			6,085			—			6,085
Share exchange with Parent (Note 2)		2,996		3		26,012		—			—			26,015			—			26,015
Cash paid to non controlling interest		—		—		—		—			—			—			(7,196	)		(7,196	)
Cash dividend declared, $0.26 per share		—		—		—		(12,716	)		—			(12,716	)		—			(12,716	)
Issuance of shares to noncontrolling interest, net of transaction costs		—		—		71,165		—			—			71,165			85,470			156,635
Net income		—		—		—		119,573			—			119,573			3,776			123,349
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment
Loss in respect of derivative instruments designated for cash flow hedge (net of related tax of $56)		—		—		—		—			91			91			—			91
Change in unrealized gains or losses in respect of the Company's share in derivative instruments of unconsolidated investment (net of related tax of $0)		—		—		—		—			1,028			1,028			—			1,028
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $73)		—		—		—		—			(118	)		(118	)		—			(118	)
Balance at December 31, 2015		49,107	$	49	$	849,223	$	148,396		$	(7,667	)	$	990,001		$	93,873		$	1,083,874
Stock-based compensation		—		—		5,157		—			—			5,157			—			5,157
Exercise of options by employees and directors		560		1		7,249		—			—			7,250			—			7,250
Cash paid to noncontrolling interest		—		—		—		—			—			—			(57,391	)		(57,391	)
Cash dividend declared, $0.52 per share		—		—		—		(25,682	)		—			(25,682	)		—			(25,682	)
Increase in noncontrolling interest in Guadeloupe		—		—		—		—			—			—			8,240			8,240
Increase in noncontrolling interest in Opal		—		—		—		—			—			—			3,697			3,697
Issuance of shares to noncontrolling interest, net of transaction costs		—		—		7,834		—			—			7,834			36,268			44,102
Net income		—		—		—		93,930			—			93,930			7,302			101,232
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment		—		—		—		—			(1,241	)		(1,241	)		(407)			(1,648	)
Loss in respect of derivative instruments designated for cash flow hedge (net of related tax of $54)		—		—		—		—			87			87			—			87
Change in unrealized gains or losses in respect of the Company's share in derivative instruments of unconsolidated investment (net of related tax of $0)		—		—		—		—			1,185			1,185			—			1,185
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $57)		—		—		—		—			(96	)		(96	)		—			(96	)
Balance at December 31, 2016		49,667	$	50	$	869,463	$	216,644		$	(7,732	)	$	1,078,425		$	91,582		$	1,170,007

The accompanying notes are an integral part of the consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Cash flows from operating activities:
Net income	$	101,516		$	123,349		$	55,015
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		105,977			107,206			100,798
Amortization of premium from senior unsecured bonds		(513	)		(306	)		(308	)
Accretion of asset retirement obligation		1,778			1,198			829
Stock-based compensation		5,157			3,955			5,571
Amortization of deferred lease income		(2,685	)		(2,685	)		(2,685	)
Income attributable to sale of tax benefits, net of interest expense		(6,962	)		(17,467	)		(13,823	)
Equity in losses of investees		7,735			5,508			3,213
Mark-to-market of derivative instruments		319			4,129			(6,960	)
Write-off of unsuccessful exploration activities		3,017			1,579			15,439
Gain on severance pay fund asset		(304	)		(119	)		1,492
Gain on sale of a subsidiary		—			—			(7,628	)
Deferred income tax provision		18,473			(39,530	)		13,135
Liability for unrecognized tax benefits		(4,647	)		2,874			2,561
Deferred lease revenues		(853	)		224			(251	)
Other		—			484			(181	)
Changes in operating assets and liabilities, net of amounts acquired:
Receivables		(33,280	)		(3,806	)		47,114
Costs and estimated earnings in excess of billings on uncompleted contracts		(27,078	)		2,673			(6,576	)
Inventories		6,297			(1,144	)		5,359
Prepaid expenses and other		(12,540	)		(2,579	)		(1,337	)
Deposits and other		(1,009	)		(648	)		584
Accounts payable and accrued expenses		(1,375	)		(339	)		(9,638	)
Due from/to related entities, net		—			451			(9	)
Billings in excess of costs and estimated earnings on uncompleted contracts		(2,262	)		9,168			16,821
Liabilities for severance pay		(786	)		(1,076	)		(3,442	)
Other long-term liabilities		3,310			(2,561	)		(903	)
Due from/to Parent		—			(513	)		(955	)
Net cash provided by operating activities		159,285			190,025			213,235
Cash flows from investing activities:
Cash acquired in organizational restructuring and share exchange with parent		—			15,391			—
Net change in restricted cash, cash equivalents and marketable securities		15,241			43,745			(42,183	)
Cash received from sale of a subsidiary		—			—			35,250
Capital expenditures		(151,930	)		(152,450	)		(151,153	)
Cash grant received from the U.S. Treasury under Section 1603 of the ARRA		—			—			27,427
Investment in unconsolidated companies		(3,569	)		—			(631	)
Cash paid for acquisition of controlling interest in a subsidiary, net of cash acquired		(20,135	)		—			—
Intangible assets acquired		—			(500	)		—
Decrease in severance pay fund asset, net of payments made to retired employees		1,862			2,843			2,128
Net cash used in investing activities		(158,531	)		(90,971	)		(129,162	)
Cash flows from financing activities:
Proceeds from sale of membership interests to noncontrolling interest, net of transaction costs		44,102			156,635			—
Proceeds from long-term loans, net of transaction costs		142,500			42,000			140,000
Proceeds from exercise of options by employees		7,249			6,085			981
Proceeds from issuance of senior unsecured notes, net of transaction costs		203,483			—			—
Purchase of Senior unsecured notes		(249,468	)		—			—
Proceeds from the sale of limited liability company interest in OPAL Geo LLC, net of transaction costs		59,897			—			—
Purchase of OFC Senior Secured Notes		(6,815	)		(30,638	)		(12,860	)
Proceeds from revolving credit lines with banks		309,400			598,800			2,830,683
Repayment of revolving credit lines with banks		(309,400	)		(619,100	)		(2,922,400	)
Cash received from noncontrolling interest		1,972			1,654			2,234
Payment for acquisition of noncontrolling interest in Crump		—			—			(1,490	)
Repayments of long-term debt		(62,052	)		(71,701	)		(111,180	)
Cash paid to noncontrolling interest		(64,065	)		(19,068	)		(11,320	)
Cash paid for interest rate cap		—			—			(1,505	)
Payments of capital leases		(1,178	)		—			—
Deferred debt issuance costs		(6,402	)		(5,316	)		(4,785	)
Cash dividends paid		(25,682	)		(12,716	)		(9,555	)
Net cash provided by (used in) financing activities		43,541			46,635			(101,197	)
Net change in cash and cash equivalents		44,295			145,689			(17,124	)
Cash and cash equivalents at beginning of period		185,919			40,230			57,354
Cash and cash equivalents at end of period	$	230,214		$	185,919		$	40,230
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest, net of interest capitalized	$	55,366		$	55,492		$	62,376
Income taxes, net	$	18,490		$	10,419		$	5,787
Supplemental non-cash investing and financing activities:
Increase (decrease) in accounts payable related to purchases of property, plant and equipment	$	(2,219	)	$	3,810		$	3,853
Accrued liabilities related to financing activities	$	6,291		$	1,665		$	658
Increase (decrease) in asset retirement cost and asset retirement obligation	$	714		$	516		$	(366	)

The accompanying notes are an integral part of the consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Business

Ormat Technologies, Inc. (the “Company”) is primarily engaged in the geothermal and recovered energy business, including the supply of equipment that is manufactured by the Company and the design and construction of power plants for projects owned by the Company or for third parties. The Company owns and operates geothermal and recovered energy-based power plants in various countries, including the United States of America (“U.S.”), Kenya, and Guatemala. The Company’s equipment manufacturing operations are located in Israel.

Most of the Company’s domestic power plant facilities are Qualifying Facilities under the Public Utility Regulatory Policies Act of 1978 (“PURPA”). The power purchase agreements (“PPAs”) for certain of such facilities are dependent upon their maintaining Qualifying Facility status. Management believes that all of the facilities located in the U.S. were in compliance with Qualifying Facility status requirements as of December 31, 2016.

Cash dividends

During the years ended December 31, 2016, 2015, and 2014, the Company’s Board of Directors declared, approved, and authorized the payment of cash dividends in the aggregate amount of $25.7 million ($0.52 per share), $12.7 million ($0.26 per share), and $9.6 million ($0.21 per share), respectively. Such dividends were paid in the years declared.

Rounding

Dollar amounts, except per share data, in the notes to these financial statements are rounded to the closest $1,000, unless otherwise indicated.

Basis of presentation

The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and include the accounts of the Company and of all majority-owned subsidiaries in which the Company exercises control over operating and financial policies, and variable interest entities in which the Company has an interest and is the primary beneficiary. Intercompany accounts and transactions have been eliminated in consolidation.

Investments in less-than-majority-owned entities or other entities in which the Company exercises significant influence over operating and financial policies are accounted for using the equity method of accounting or consolidated if they are a variable interest entity in which the Company has an interest and is the primary beneficiary. Under the equity method, original investments are recorded at cost and adjusted by the Company’s share of undistributed earnings or losses of such companies. The Company’s earnings or losses in investments accounted for under the equity method have been reflected as “equity in income (losses) of investees, net” on the Company’s consolidated statements of operations and comprehensive income (loss).

Cash and cash equivalents

The Company considers all highly liquid instruments, with an original maturity of three months or less, to be cash equivalents.

Restricted cash, cash equivalents, and marketable securities

Under the terms of certain long-term debt agreements, the Company is required to maintain certain debt service reserves, cash collateral and operating fund accounts that have been classified as restricted cash and cash equivalents. Funds that will be used to satisfy obligations due during the next twelve months are classified as current restricted cash and cash equivalents, with the remainder classified as non-current restricted cash and cash equivalents. Such amounts were invested primarily in money market accounts and commercial paper with a minimum investment grade of “AA”.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Concentration of credit risk

Financial instruments which potentially subject the Company to concentration of credit risk consist principally of temporary cash investments and accounts receivable.

The Company places its temporary cash investments with high credit quality financial institutions located in the U.S. and in foreign countries. At December 31, 2016 and 2015, the Company had deposits totaling $72.5 million and $19.0 million, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account. At December 31, 2016 and 2015, the Company’s deposits in foreign countries of approximately $166.2 million and $181.0 million, respectively, were not insured.

At December 31, 2016 and 2015, accounts receivable related to operations in foreign countries amounted to approximately $53.3 million and $27.8 million, respectively. At December 31, 2016, and 2015, accounts receivable from the Company’s major customers (see Note 20) amounted to approximately 60% and 66%, respectively, of the Company’s accounts receivable.

The Company has historically been able to collect on substantially all of its receivable balances, and accordingly, no provision for doubtful accounts has been made.

Inventories

Inventories consist primarily of raw material parts and sub-assemblies for power units, and are stated at the lower of cost or market value, using the weighted-average cost method. Inventories are reduced by a provision for slow-moving and obsolete inventories. This provision was not material at December 31, 2016 and 2015.

Deposits and other

Deposits and other consist primarily of performance bonds for construction projects, long-term insurance contract and receivables, and derivative instruments.

Deferred charges

Deferred charges represent prepaid income taxes on intercompany sales. Such amounts are amortized using the straight-line method and included in income tax provision over the life of the related property, plant and equipment.

Property, plant and equipment, net

Property, plant and equipment are stated at cost. All costs associated with the acquisition, development and construction of power plants operated by the Company are capitalized. Major improvements are capitalized and repairs and maintenance (including major maintenance) costs are expensed. Power plants operated by the Company, which include geothermal wells and exploration and resource development costs, are depreciated using the straight-line method over their estimated useful lives, which range from 15 to 30 years. The other assets are depreciated using the straight-line method over the following estimated useful lives of the assets:

Buildings (in years)		25
Leasehold improvements (in years)	15	-	20
Machinery and equipment — manufacturing and drilling (in years)		10
Machinery and equipment — computers (in years)	3	-	5
Office equipment — furniture and fixtures (in years)	5	-	15
Office equipment — other (in years)	5	-	10
Automobiles (in years)	5	-	7

The cost and accumulated depreciation of items sold or retired are removed from the accounts. Any resulting gain or loss recognized currently and is recorded in the accompanying statements of operations.

The Company capitalizes interest costs as part of constructing power plant facilities. Such capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life. Capitalized interest costs amounted to $3.3 million, $4.1 million, and $3.2 million for the years ended December 31, 2016, 2015, and 2014, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash Grants

From 2009 to 2014, the Company was awarded cash grants from the U.S. Department of the Treasury (“U.S. Treasury”) for Specified Energy Property in Lieu of Tax Credits under Section 1603 of the American Recovery and Reinvestment Act of 2009 (“ARRA”). The Company recorded the cash grant as a reduction in the carrying value of the related plant and amortized the grants as a reduction in depreciation expense over the plant’s estimated useful life.

Exploration and development costs

The Company capitalizes costs incurred in connection with the exploration and development of geothermal resources once it acquires land rights to the potential geothermal resource. Prior to acquiring land rights, the Company makes an initial assessment that an economically feasible geothermal reservoir is probable on that land. The Company determines the economic feasibility of potential geothermal resources internally, with all available data and external assessments vetted through the exploration department and occasionally using outside service providers. Costs associated with the initial assessment are expensed and included in cost of electricity revenues in the consolidated statements of operations and comprehensive income (loss). Such costs were immaterial during the years ended December 31, 2016, 2015, and 2014. It normally takes two to three years from the time active exploration of a particular geothermal resource begins to the time a production well is in operation, assuming the resource is commercially viable. However, in certain sites the process may take longer due to permitting delays, transmission constrains or any other commercial milestones that are required to be reached in order to pursue the development process.

In most cases, the Company obtains the right to conduct the geothermal development and operations on land owned by the Bureau of Land Management (“BLM”), various states or with private parties. In consideration for certain of these leases, the Company may pay an up-front bonus payment which is a component of the competitive lease process. The up-front bonus payments and other related costs, such as legal fees, are capitalized and included in construction-in-process. The annual land lease payments made during the exploration, development and construction phase are expensed as incurred and included in “electricity cost of revenues” in the consolidated statements of operations and comprehensive income (loss). Upon commencement of power generation on the leased land, the Company begins to pay to the lessors long-term royalty payments based on the utilization of the geothermal resources as defined in the respective agreements. Such payments are expensed when the related revenues are earned and included in “electricity cost of revenues” in the consolidated statements of operations and comprehensive income (loss).

Following the acquisition of land rights to the potential geothermal resource, the Company conducts further studies and surveys, including water and soil analyses among others, and augments its database with the results of these studies. The Company then initiates a suite of geophysical surveys to assess the resource and determine drilling locations. If the results of these activities support the initial assessment of the feasibility of the geothermal resource, the Company then proceeds to exploratory drilling and other related activities which may include drilling of temperature gradient holes, drilling of slim holes, building access roads to drilling locations, drilling full size production and/or injection wells and flow tests. If the slim hole supports a conclusion that the geothermal resource will support a commercially viable power plant, it may be converted to a full-size commercial well, used either for extraction or re-injection or geothermal fluids, or be used as an observation well to monitor and define the geothermal resource. Costs associated with these activities and other directly attributable costs, including interest once physical exploration activities begin and permitting costs are capitalized and included in “construction-in-process”. If the Company concludes that a geothermal resource will not support commercial operations, capitalized costs are expensed in the period such determination is made.

When deciding whether to continue holding lease rights and/or to pursue exploration activity, we diligently prioritize our prospective investments, taking into account resource and probability assessments in order to make informed decisions about whether a particular project will support commercial operations. As a result, write-off of unsuccessful activities for the year ended December 31, 2016, 2015 and 2014, was $3.0 million, $1.6 million, and $15.4 million. In 2016 and 2015, the write-offs included the exploration costs related to the Company’s exploration activities primarily in the Twilight site in Oregon and the Maui site in Hawaii of $1.0 million, respectively. In 2014, the write-offs included the exploration costs related to the Company’s exploration activities in the Wister site in California of $8.1 million and the Mount Spur site in Alaska of $7.3 million.

Grants received from the U.S. Department of Energy (“DOE”) are offset against the related exploration and development costs. Such grants amounted to $0.3 million, $0.8 million, and $1.7 million for the years ended December 31, 2016, 2015, and 2014, respectively.

All exploration and development costs that are being capitalized, including the up-front bonus payments made to secure land leases, will be depreciated over their estimated useful lives when the related geothermal power plant is substantially complete and ready for use. A geothermal power plant is substantially complete and ready for use when electricity generation commences.

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Asset retirement obligation

The Company records the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. The Company’s legal liabilities include plugging wells and post-closure costs of power producing sites. When a new liability for asset retirement obligations is recorded, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. At retirement, the obligation is settled for its recorded amount at a gain or loss.

Deferred financing and lease transaction costs

Deferred financing costs are amortized over the term of the related obligation using the effective interest method. Amortization of deferred financing costs is presented as interest expense in the consolidated statements of operations and comprehensive income (loss). Accumulated amortization related to deferred financing costs amounted to $31.1 million and $37.2 million at December 31, 2016 and 2015, respectively. Amortization expense for the years ended December 31, 2016, 2015, and 2014 amounted to $6.9 million, $8.8 million, and $6.5 million, respectively. During the years ended December 31, 2016, 2015 and 2014 amounts of $0.1 million, $0.5 million and $0.7 million, respectively, were written-off as a result of the extinguishment of liability.

Deferred transaction costs relating to the Puna operating lease (see Note 13) in the amount of $4.2 million are amortized using the straight-line method over the 23-year term of the lease. Amortization of deferred transaction costs is presented in cost of revenues in the consolidated statements of operations and comprehensive income (loss). Accumulated amortization related to deferred lease costs amounted to $2.1 million and $2.0 million at December 31, 2016 and 2015, respectively. Amortization expense for each of the years ended December 31, 2016, 2015, and 2014 amounted to $0.2 million.

Goodwill

Goodwill represents the excess of the fair value of consideration transferred in the Guadeloupe business combination transaction over the fair value of tangible and intangible assets acquired net of the fair value of liabilities assumed and the fair value of any noncontrolling interest in the acquisition. Goodwill is not amortized but rather subject to periodic impairment testing on an annual basis or if an event occurs or circumstances change that would more likely than not reduce the fair value of reporting unit below its carrying amount.

Intangible assets

Intangible assets consist of allocated acquisition costs of PPAs, which are amortized using the straight-line method over the 13 to 25-year terms of the agreements (see Note 10).

Impairment of long-lived assets and long-lived assets to be disposed of

The Company evaluates long-lived assets, such as property, plant and equipment and construction-in-process for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Factors which could trigger an impairment include, among others, significant underperformance relative to historical or projected future operating results, significant changes in the Company’s use of assets or its overall business strategy, negative industry or economic trends, a determination that an exploration project will not support commercial operations, a determination that a suspended project is not likely to be completed, a significant increase in costs necessary to complete a project, legal factors relating to its business or when it concludes that it is more likely than not that an asset will be disposed of or sold.

The Company tests its operating plants that are operated together as a complex for impairment at the complex level because the cash flows of such plants result from significant shared operating activities. For example, the operating power plants in a complex are managed under a combined operation management generally with one central control room that controls all of the power plants in a complex and one maintenance group that services all of the power plants in a complex. As a result, the cash flows from individual plants within a complex are not largely independent of the cash flows of other plants within the complex. The Company tests for impairment its operating plants which are not operated as a complex as well as its projects under exploration, development or construction that are not part of an existing complex at the plant or project level. To the extent an operating plant becomes part of a complex, the Company will test for impairment at the complex level.

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated future net undiscounted cash flows expected to be generated by the asset. The significant assumptions that the Company uses in estimating its undiscounted future cash flows include: (i) projected generating capacity of the complex or power plant and rates to be received under the respective PPA(s) and expected market rates thereafter and (ii) projected operating expenses of the relevant complex or power plant. Estimates of future cash flows used to test recoverability of a long-lived asset under development also include cash flows associated with all future expenditures necessary to develop the asset.

If the assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. Management believes that no impairment exists for long-lived assets; however, estimates as to the recoverability of such assets may change based on revised circumstances. If actual cash flows differ significantly from the Company’s current estimates, a material impairment charge may be required in the future.

Derivative instruments

Derivative instruments (including certain derivative instruments embedded in other contracts) are measured at their fair value and recorded as either assets or liabilities unless exempted from derivative treatment as a normal purchase and sale. All changes in the fair value of derivatives are recognized in earnings unless specific hedge criteria are met, which requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

The Company maintains a risk management strategy that incorporates the use of swap contracts and put options on oil and natural gas prices, forward exchange contracts, interest rate swaps, and interest rate caps to minimize significant fluctuation in cash flows and/or earnings that are caused by oil and natural gas prices, exchange rate or interest rate volatility. Gains or losses on contracts that initially qualify for cash flow hedge accounting, net of related taxes, are included as a component of other comprehensive income or loss and accumulated other comprehensive income or loss are subsequently reclassified into earnings when the hedged forecasted transaction affects earnings. Gains or losses on contracts that are not designated as a cash flow hedge are included currently in earnings.

Foreign currency translation

The U.S. dollar is the functional currency for all of the Company’s consolidated operations and those of its equity affiliates except for the Guadeloupe power plant. For those entities, all gains and losses from currency translations are included within the line item “Derivatives and foreign currency transaction gains (losses)” within the consolidated statements of operations and comprehensive income (loss). The Euro is the functional currency of the Guadeloupe power plant and thus gains and losses from currency translation adjustments related to Guadeloupe are included as currency translation adjustments in accumulated other comprehensive income in the consolidated statements of equity and in comprehensive income.

Comprehensive income (loss) reporting

Comprehensive income (loss) includes net income or loss plus other comprehensive income (loss), which for the Company consists of changes in unrealized gains or losses in respect of the Company’s share in derivatives instruments of unconsolidated investment, foreign currency translation adjustments and the mark-to-market gains or losses on derivative instruments designated as a cash flow hedge. For the years ended December 31, 2016, 2015 and 2014, the Company reclassified $9 thousand, $27 thousand and $141 thousand, respectively, from other comprehensive income, of which $12.0 thousand, $44 thousand and $228 thousand, respectively, were recorded to reduce interest expense and $3.0 thousand, $17 thousand and $87 thousand, respectively, were recorded against the income tax provision, in the consolidated statements of operations and comprehensive income (loss).

Revenues and cost of revenues

Revenues are primarily related to: (i) sale of electricity from geothermal and recovered energy-based power plants owned and operated by the Company and (ii) geothermal and recovered energy-based power plant equipment engineering, sale, construction and installation, and operating services.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Revenues related to the sale of electricity from geothermal and recovered energy-based power plants and capacity payments are recorded based upon output delivered and capacity provided at rates specified under relevant contract terms. For PPAs agreed to, modified, or acquired in business combinations on or after July 1, 2003, the Company determines whether such PPAs contain a lease element requiring lease accounting. Revenue from such PPAs are accounted for in electricity revenues. The lease element of the PPAs is also assessed in accordance with the revenue arrangements with multiple deliverables guidance, which requires that revenues be allocated to the separate earnings processes based on their relative fair value. PPAs with minimum lease rentals which vary over time are generally recognized on the straight-line basis over the term of the PPAs. PPAs with contingent rentals are recognized when earned.

Revenues from engineering, operating services, and parts and product sales are recorded upon providing the service or delivery of the products and parts and when collectability is reasonably assured. Revenues from the supply and/or construction of geothermal and recovered energy-based power plant equipment and other equipment to third parties are recognized using the percentage-of-completion method. Revenue is recognized based on the percentage relationship that incurred costs bear to total estimated costs. Costs include direct material, labor, and indirect costs. Selling, marketing, general, and administrative costs are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in job performance, job conditions, and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and revenues and are recognized in the period in which the revisions are determined.

In specific instances where there is a lack of dependable estimates or inherent risks cause forecast to be doubtful, then the completed-contract method is followed. Revenue is recognized when the contract is substantially complete and when collectability is reasonably assured. Costs that are closely associated with the project are deferred as contract costs and recognized similarly to the associated revenues.

Warranty on products sold

The Company generally provides a one-year warranty against defects in workmanship and materials related to the sale of products for electricity generation. Estimated future warranty obligations are included in operating expenses in the period in which the related revenue is recognized. Such charges are immaterial for the years ended December 31, 2016, 2015, and 2014.

Research and development

Research and development costs incurred by the Company for the development of existing and new geothermal, recovered energy and remote power technologies are expensed as incurred. Grants received from the DOE are offset against the related research and development expenses. Such grants amounted to $0 million, $0 million, and $0.6 million for the years ended December 31, 2016, 2015, and 2014, respectively.

Stock-based compensation

The Company accounts for stock-based compensation using the fair value method whereby compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the requisite employee service period (generally the vesting period of the grant). Prior to 2016, the Company used the Black-Scholes formula to estimate the fair value of the stock-based compensation. In 2016, the Company used the Exercise Multiple-Based Lattice SAR-Pricing Model to value the stock-based compensation awards to reflect accumulated historic data retained of behavioral parameters.

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Tax monetization Transactions

The Company has three tax monetization transactions, OPC, ORTP and Opal, as described in Note 14.  The purpose of these transactions is to form tax partnerships, whereby investors provide cash in exchange for equity interests that provide the holder a right to the majority of tax benefits associated with a renewable energy project.  We account for a portion of the proceeds from the transaction as debt under ASC 470.  Given that a portion of these transactions is structured as a purchase of an equity interest we also classify a portion as noncontrolling interest consistent with guidance in ASC 810.  The portion recorded to noncontrolling interest is initially measured as the fair value of the discounted Tax Attributes and cash distributions which represents the partner's residual economic interest.  The residual proceeds is recognized as the initial carrying value of the debt which is classified as a liability associated with sale tax benefits. We apply the effective interest rate method to the liability component as described by ASC 835 and CON 7.  The tax benefits and cash distributions realized by the partner each period are treated as the debt servicing amounts, giving rise to income attributable to the sale of tax benefits.  The deferred transaction costs have been capitalized and amortized using the effective interest method.

Income taxes

Income taxes are accounted for using the asset and liability approach, which requires the recognition of taxes payable or refundable for the current year and deferred tax assets and liabilities for the future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. The measurement of current and deferred tax assets and liabilities are based on provisions of the enacted tax law. The effects of future changes in tax laws or rates are not anticipated. The Company accounts for investment tax credits and production tax credits as a reduction to income taxes in the year in which the credit arises. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that, based on available evidence, are not, more likely than not expected to be realized. A full valuation allowance has been established to offset the Company’s U.S. deferred tax assets. Tax benefits from uncertain tax positions are recognized only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. Interest and penalties assessed by taxing authorities on an underpayment of income taxes are included as a component of income tax provision in the consolidated statements of operations and comprehensive income.

Earnings (loss) per share

Basic earnings (loss) per share attributable to the Company’s stockholders (“earnings (loss) per share”) is computed by dividing net income or loss attributable to the Company’s stockholders by the weighted average number of shares of common stock outstanding for the period. The Company does not have any equity instruments that are dilutive, except for stock-based awards.

The table below shows the reconciliation of the number of shares used in the computation of basic and diluted earnings per share:

	Year Ended December 31,
	2016		2015		2014
	(In thousands)
Weighted average number of shares used in computation of basic earnings per share		49,469		48,562		45,508
Add:
Additional shares from the assumed exercise of employee stock options		671		625		351
Weighted average number of shares used in computation of diluted earnings per share		50,140		49,187		45,859

The number of stock-based awards that could potentially dilute future earnings per share and were not included in the computation of diluted earnings per share because to do so would have been anti-dilutive was 102,793, 467,766, and 3,237,593, respectively, for the years ended December 31, 2016, 2015, and 2014.

Use of estimates in preparation of financial statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of such financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. The most significant estimates with regard to the Company’s consolidated financial statements relate to the useful lives of property, plant and equipment, impairment of long-lived assets and assets to be disposed of, revenue recognition of product sales using the percentage of completion method, asset retirement obligations, and the provision for income taxes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

New Accounting Pronouncements

New accounting pronouncements effective in the year ended December 31, 2016

Amendments to Fair Value Measurement

In June 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-10, Amendment to Fair Value Measurement, Subtopic 820-10. The amendment provides that the reporting entity shall disclose for each class of assets and liabilities measured at fair value in the statement of financial position the following information: for recurring fair value measurements, the fair value measurement at the end of the reporting period, and for non-recurring fair value measurement, the fair value measurement at the relevant measurement date and the reason for the measurement. The amendments in this update are effective for annual reporting periods beginning after December 15, 2015, including interim periods within those reporting periods. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements.

Amendments to the Consolidation Analysis

In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis, Topic 810. The update provides that all reporting entities that hold a variable interest in other legal entities will need to re-evaluate their consolidation conclusions and potentially revise their disclosures. This amendment affects both variable interest entity (“VIE”) and voting interest entity (“VOE”) consolidation models. The update does not change the general order in which the consolidation models are applied. A reporting entity that holds an economic interest in, or is otherwise involved with, another legal entity (i.e. has a variable interest) should first determine if the VIE model applies, and if so, whether it holds a controlling financial interest under that model. If the entity being evaluated for consolidation is not a VIE, then the VOE model should be applied to determine whether the entity should be consolidated by the reporting entity. Since consolidation is only assessed for legal entities, the determination of whether there is a legal entity is important. It is often clear when the entity is incorporated, but unincorporated structures can also be legal entities and judgment may be required to make that determination. The update contains a new example that highlights the discretion used to make this legal entity determination. The update is effective for annual reporting periods beginning after December 15, 2015, including interim periods within those reporting periods. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements.

Simplifying the Presentation of Debt Costs

In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest: Simplifying the Presentation of Debt Costs, Subtopic 835-30. The update provides that debt issuance costs related to a recognized debt liability be presented in the balance sheet as direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The Company retrospectively adopted this update in its interim period beginning January 1, 2016. The impact of the adoption resulted in a reclassification of debt issuance costs totaling $17.7 million and $19.1 million as of December 31, 2016 and December 31, 2015, respectively.

In August 2015, the FASB issued ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements, Subtopic 835-30. The update clarifies that given the absence of authoritative guidance within Update 2015-03 for debt issuance costs described below, debt issuance costs related to line-of-credit arrangements can be deferred and presented as assets and subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings under the line-of-credit arrangement. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The Company adopted this update in its interim period beginning January 1, 2016 and continues to present debt issuance costs related to such line-of-credit arrangements as assets amortized ratably over the respective term of the line-of credit arrangements. Debt issuance costs related to such line-of-credit arrangements as of December 31, 2016 and December 31, 2015, totaled $1.1 million and $1.0 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

New accounting pronouncements effective in future periods

Business Combinations

In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805). The update clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this update primarily provide a screen to determine when a set of assets and activities is not a business and by that reduces the number of transactions that need to be further evaluated. The amendments in this update should be applied prospectively and are effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Statement of Cash Flows

In November 2016, the FASB issued ASU 2016-018, Statement of Cash Flows (Topic 230) – Restricted Cash. The amendments in this update require that a statement of cash flows explain the changes during the period in total cash, cash equivalents, and the amounts generally described as restricted cash or cash equivalents. Therefore, amounts of restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendments in this update should be applied retrospectively for each period presented and are effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Intra-Entity Transfers of Assets Other than Inventory

      In October 2016, the FASB issued ASU 2016-16, Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory. The amendments in this update require that the entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The new guidance does not apply to intra-entity transfers on inventory. The amendments in this update should be applied for each period presented and are effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The modified retrospective approach will be required for transition to the new guidance, with cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. Early adoption is permitted in the first quarter of 2017. The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Interests Held through Related Parties that are under Common Control

      In October 2016, the FASB issued ASU 2016-17, Consolidation (Topic 810): Interests held through Related Parties that are under Common Control. The amendments in this update require that if a decision maker is required to evaluate whether it is the primary beneficiary of a VIE, it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The amendments in this update should be applied retrospectively for each period presented and are effective for financial statements issued for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Improvement to Employee Share-Based Payment Accounting

In March 2016, the FASB issued ASU 2016-09, Improvement to Employee Share-Based Payment Accounting, an update to the guidance on stock-based compensation. Under the new guidance, all excess tax benefits and tax deficiencies will be recognized in the income statement as they occur. This will replace the current guidance, which requires tax benefits that exceed compensation cost (windfalls) to be recognized in equity. It will also eliminate the need to maintain a “windfall pool,” and will remove the requirement to delay recognizing a windfall until it reduces current taxes payable. The new guidance will also change the cash flow presentation of excess tax benefits, classifying them as operating inflows, consistent with other cash flows related to income taxes. Today, windfalls are classified as financing activities. Also, this will affect the dilutive effects in earnings per share, as there will no longer be excess tax benefits recognized in additional paid in capital. Today those excess tax benefits are included in assumed proceeds from applying the treasury stock method when computing diluted EPS. Under the amended guidance, companies will be able to make an accounting policy election to either (1) continue to estimate forfeitures or (2) account for forfeitures as they occur. This updated guidance is effective for annual and interim periods beginning after December 15, 2016. Early adoption is permitted. The Company is currently evaluating the potential impact, if any, of the adoption of this update on its consolidated financial statements, however, any impact is not expected to be material.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Leases

In February 2016, the FASB issued ASU 2016-02, Leases, Topic 842. The amendment in this Update introduce a number of changes and simplifications from previous guidance, primarily the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The Update retains the distinction between finance leases and operating leases and the classification criteria between the two types remain substantially similar. Also, lessor accounting remains largely unchanged from previous guidance, however, key aspects in the Update were aligned with the revenue recognition guidance in Topic 606. Additionally, the Update defines a lease as a contract, or part of a contract, that conveys the right to control the use of identified asset for a period of time in exchange for considerations. Control over the use of the identified means that the customer has both (a) the right to obtain substantially all of the economic benefits from the use of the asset and (b) the right to direct the use of the asset. The amendments in this update are effective for annual reporting periods beginning after December 15, 2018, including interim periods within those reporting periods. Early adoption is permitted. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities. The update primarily requires that an entity should present separately, in other comprehensive income, the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk if the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. The application of this update should be by means of cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted as of the beginning of the fiscal year of adoption. The Company is currently evaluating the potential impact, if any, of the adoption of this update on its consolidated financial statements.

Simplifying the Measurement of Inventory

In July 2015, the FASB issued ASU 2015-11, Simplifying the Measurement of Inventory, Topic 330. The update contains no amendments to disclosure requirements, but replaces the concept of ‘lower of cost or market’ with that of ‘lower of cost and net realizable value’. The amendments in this update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within those reporting periods. The amendments should be applied prospectively with early adoption permitted. The Company estimates that the potential impact, if any, of the adoption of this update on its consolidated financial statements is immaterial.

Revenues from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenues from Contracts with Customers, Topic 606, which was a joint project of the FASB and the International Accounting Standards Board to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The update provides that an entity should recognize revenue in connection with the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Specifically, an entity is required to apply each of the following steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contracts; (3) determine the transaction price; (4) allocate the transaction price to the performance obligation in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also prescribes additional financial presentations and disclosures. The amendments in this update are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those reporting periods. Early adoption is permitted no earlier than 2017 for calendar fiscal year entities. The Company expects the adoption of this standard to have an immaterial impact, if any, on its Electricity segment as it accounts for its PPA’s under ASC 840, Leases. The Company still evaluates the potential impact of the adoption of the standard on its Product segment, however, it believes that such impact, if any, will be immaterial.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In March 2016, the FASB issued ASU 2016-08, Principal versus Agent Considerations. The amendment in this Update do not change the core principal of the guidance and are intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations. When another entity is involved in providing goods or services to a customer, an entity is required to determine if the nature of its promise is to provide the specific good or service itself (that is, the entity is a principal) or to arrange for that good or service to be provided by the other party (that is, the entity is an agent). The guidance includes indicators to assist an entity in determining whether it acts as a principal or agent in a specified transaction. The amendments in this update are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those reporting periods. Early adoption is permitted no earlier than 2017 for calendar fiscal year entities. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements, however, it believes that any such impact, if any, will be immaterial.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 — SHARE EXCHANGE TRANSACTION

Share exchange transaction

On February 12, 2015, the Company completed the share exchange transaction with its then-parent entity, Ormat Industries Ltd. ("OIL") following which, the Company became a noncontrolled public company and its public float increased from approximately 40% to approximately 76% of its total shares outstanding. Under the terms of the share exchange, OIL shareholders received 0.2592 shares in the Company for each share in OIL, or an aggregate of approximately 30.2 million shares, reflecting a net issuance of approximately 3.0 million shares (after deducting the 27.2 million shares that OIL held in the Company). Consequently, the number of total shares of the Company outstanding increased from approximately 45.5 million shares to approximately 48.5 million shares as of the closing of the share exchange.

In exchange, the Company also received $15.4 million in cash, $0.6 million in other assets and $12.1 million in land and buildings and assumed $0.5 million in liabilities. OIL's principal business purpose was to hold its interest in the Company and the transaction resulted in a transfer of non-material assets from OIL to the Company. Therefore, there was no change in the reporting entity as a result of the transaction and the Company recognized the transfer of net assets at their carrying value as presented in OIL's financial statements. Any activities of OIL will be accounted for prospectively by the Company.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3 — NORTHLEAF TRANSACTIONS AND BUSINESS AQUISITION

Northleaf transactions

On April 30, 2015, Ormat Nevada Inc. (“Ormat Nevada”), a wholly-owned subsidiary of the Company, closed the sale of approximately 36.75% of the aggregate membership interests in ORPD LLC (“ORPD”), a new holding company and subsidiary of Ormat Nevada, that indirectly owns the Puna geothermal power plant in Hawaii, the Don A. Campbell geothermal power plant in Nevada, and nine power plant units across three recovered energy generation assets known as OREG 1, OREG 2 and OREG 3 to Northleaf Geothermal Holdings, LLC for $162.3 million. The net proceeds to the Company were $156.8 million after payment of $5.5 million of transaction costs. The sale was made under the Agreement for Purchase of Membership Interests dated February 5, 2015. This transaction closed on April 30, 2015 and resulted in a taxable gain in the U.S. of approximately $102.1 million, for which the Company utilized a portion of its Net Operating Loss (“NOL”) and tax credit carryforwards to fully offset the tax impact of the gain.

Following the transaction, the Company maintains control of ORPD and continues to consolidate the entity with non-controlling interest being recorded. Consequently, the Company recorded the net proceeds from the issuance of membership interests as an increase to additional paid-in capital of $71.3 million and non- controlling interests of $85.5 million. See Note 19 for tax details.

On November 23, 2016, Ormat Nevada, closed a follow-on sale of 36.75% equity interest in the second phase of the Don A. Campbell power plant for proceeds of approximately $44.2 million. The Don A. Campbell commenced operations in September 2015 and sells its electricity to SCPPA under a 20 year PPA. Following the closing, the power plant was contributed to the existing ORPD, as agreed upon under the ORPD agreement with Northleaf Geothermal Holdings, LLC that was executed on April 30, 2015. The net proceeds to the Company were $44.1 million after payment of $0.1 million of transaction costs and resulted in a taxable gain in the U.S. of approximately $21.4 million, for which the Company utilized a portion of its Net Operating Loss (“NOL”) and tax credit carryforwards to fully offset the tax impact of the gain.

Following the transaction, the Company continue to maintain control of ORPD and consolidate the entity with additional noncontrolling interest being recorded. Consequently, the Company recorded the net proceeds from the issuance of membership interests as an increase to additional paid-in capital of $7.8 million and non- controlling interests of $36.3 million. See Note 19 for tax details.

Guadeloupe power plant transaction

In July 2016, we announced that we closed the previously announced acquisition of Geothermie Bouillante SA (“GB”). GB owns and operates the 14.75 MW Bouillante geothermal power plant located in Guadeloupe Island, a French territory in the Caribbean, which currently generates approximately 13 MW. GB also owns two exploration licenses providing an expansion potential of up to 45 MW of capacity.

Pursuant to the terms of an Amended and Restated Investment Agreement (“Investment Agreement”) and Shareholders Agreement with Sageos Holding (“Sageos”), a wholly owned subsidiary of Bureau de Recherches Géologiques et Minières (“BRGM”), the Company together with Caisse des Dépôts et Consignations (“CDC”), a French state-owned financial organization, acquired an approximately 80% interest in GB, allocated 75% to the Company and 25% to CDC. The Company and CDC will gradually increase their combined interest in GB to 85% and Sageos will hold the remaining balance. As part of the agreement, CDC will pay the Company a premium.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pursuant to the agreements, the Company paid approximately $20.6 million to Sageos for its approximately 60% interest in GB. In addition, the Company is committed to further invest $8.4 million (approximately €7.5 million) in the next two years, which will increase the Company’s interest to 63.75%. The cash will be used mainly for the enhancement of the power plant.

The Company has planned modifications to the existing equipment as well as to further develop the asset, with a potential of reaching a total of 45 MW in phased development by 2021. Under the Investment Agreement, the Company will pay Sageos an additional amount of up to $13.4 million (approximately €12 million) subject to the achievement of agreed production thresholds and capacity expansion within a defined time period.

The Bouillante power plant sells its electricity under a 15-year PPA that was entered into in February 2016 with Électricité de France S.A. (“EDF”), the French electric utility. The Company plans to optimize the use of the resource at the existing facilities and recover its current production to its design capacity of 14.75 MW by mid-2017.

The Company accounted for the transaction based on the provision of Accounting Standard Codification 805, Business Combinations, and consequently recorded intangible asset of $33.0 million pertaining to the 15-year PPA with EDF and $7.1 million of goodwill. Additionally, following the transaction, the Company gained control over GB effective July 5, 2016 and consolidated the entity with redeemable noncontrolling interest of $5.0 million and noncontrolling interest of $8.3 million being recorded. The redeemable noncontrolling interest pertains to Sageos right to sell its equity interest in GB to the Company for cash considerations. The noncontrolling interest pertains to CDC and was included under noncontrolling interest in the consolidated statements of equity.

The revenues of GB of approximately $8.1 million were included in the Company’s consolidated statements of operations and comprehensive income for year ended December 31, 2016.

Viridity Transaction

On December 29, 2016 the Company entered into a definitive agreement to acquire substantially all of the business and assets of Viridity Energy, Inc. (“Viridity”), a privately held Philadelphia-based company engaged in demand response, energy management and storage of energy. The acquisition is expected to close early 2017. Initial consideration for the acquisition is $35 million, which will be paid at closing and is subject to adjustment in certain cases. Additional contingent consideration will be payable in two installments upon the achievement of certain performance milestones measured at the end of fiscal years 2017 and 2020. Using proprietary software and solutions, Viridity serves primarily retail energy providers, utilities, and large industrial and commercial clients. Viridity’s offerings enable its clients to optimize and monetize their energy management, demand response and storage facilities potential by interacting on their behalf with regional transmission organizations and independent system operators. Founded in 2008, Viridity has under contract over 850 MW across 3,000 sites, including management of a portfolio of non-utility storage assets located in the northeastern US with over 80,000 operational market hours.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 4 — INVENTORIES

Inventories consist of the following:

	December 31,
	2016		2015
	(Dollars in thousands)
Raw materials and purchased parts for assembly	$	5,429	$	8,819
Self-manufactured assembly parts and finished products		6,571		9,255
Total	$	12,000	$	18,074

NOTE 5 — COST AND ESTIMATED EARNINGS ON UNCOMPLETED CONTRACTS

Cost and estimated earnings on uncompleted contracts consist of the following:

	December 31,
	2016			2015
	(Dollars in thousands)
Costs and estimated earnings incurred on uncompleted contracts	$	402,357		$	279,176
Less billings to date		(381,789	)		(287,948	)
Total	$	20,568		$	(8,772	)

These amounts are included in the consolidated balance sheets under the following captions:

	December 31,
	2016			2015
	(Dollars in thousands)
Costs and estimated earnings in excess of billings on uncompleted contracts	$	52,198		$	25,120
Billings in excess of costs and estimated earnings on uncompleted contracts		(31,630	)		(33,892	)
Total	$	20,568		$	(8,772	)

The completion costs of the Company’s construction contracts are subject to estimation. Due to uncertainties inherent in the estimation process, it is reasonably possible that estimated contract earnings will be further revised in the near term.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6 — Accumulated loss of unconsolidated company in excess of investment

Accumulated loss of unconsolidated company in excess of investment mainly consist of the following:

	December 31,
	2016			2015
	(Dollars in thousands)
Sarulla	$	(11,081	)	$	(8,100	)

The Sarulla Project

The Company holds a 12.75% equity interest in a consortium which is in the process of developing the Sarulla geothermal power project in Indonesia with an expected generating capacity of approximately 330 megawatts (“MW”). The Sarulla project is located in Tapanuli Utara, North Sumatra, Indonesia and will be owned and operated by the consortium members under the framework of a Joint Operating Contract (“JOC”) and Energy Sales Contract (“ESC”) that were signed on April 4, 2013. Under the JOC, PT Pertamina Geothermal Energy (“PGE”), the concession holder for the project, has provided the consortium with the right to use the geothermal field, and under the ESC, PT PLN, the state electric utility, will be the off-taker at Sarulla for a period of 30 years. In addition to its equity holdings in the consortium, the Company designed the Sarulla plant and will supply its Ormat Energy Converters (“OECs”) to the power plant, as further described below.

The project is being constructed in three phases of a total 321 MW, utilizing both steam and brine extracted from the geothermal field to increase the power plant’s efficiency. The first phase with 110 MW capacity is currently under testing and expected to commence operation in March 2017. For the second phase power plant, engineering and procurement has been substantially completed, site construction is in progress and all of the major generating units including those to be supplied by Ormat were delivered. For the third phase, engineering, procurement and construction work at the site are in progress and manufacturing of equipment to be supplied by Ormat is underway as planned. Drilling for the second and third phases is still ongoing and the project has achieved to date, based on preliminary estimates, approximately 80% of the required production capacity and over 85% of the required injection capacity. The project has missed a few milestones defined under the loan documents, but has received waivers from the lenders and as of now the project is in compliance with lenders requirements. The project is still experiencing delays in the field development and cost overruns resulting from delays and excess drilling costs. Due to the cost overrun in drilling, the lenders have requested from the sponsors to commit for additional equity. The sponsors have agreed and financing documents were revised to reflect this request. With respect to Ormat’s role as a supplier, all contractual milestones under the supply agreement were achieved.

On May 16, 2014, the consortium closed $1.17 billion in financing for the development of the Sarulla project with a consortium of lenders comprised of Japan Bank for International Cooperation (“JBIC”), the Asian Development Bank and six commercial banks and obtained construction and term loans on a limited recourse basis backed by a political risk guarantee from JBIC. Of the $1.17 billion, $0.1 billion (which was drawn down by the Sarulla project company on May 23, 2014) bears a fixed interest rate and $1.07 billion bears interest at a rate linked to LIBOR.

The Sarulla consortium entered into interest rate swap agreements with various international banks in order to fix the Libor interest rate on up to $0.96 billion of the $1.07 billion credit facility at a rate of 3.4565%. The interest rate swap became effective as of June 4, 2014 along with the second draw-down by the project company of $50.0 million.

The Sarulla project company accounted for the interest rate swap as a cash flow hedge upon which changes in the fair value of the hedging instrument, relative to the effective portion, will be recorded in other comprehensive income. As such, during the year ended December 31, 2016 and 2015, the project recorded a gain of $9.3 million and $8.0 million, respectively, net of deferred tax, of which the Company's share was $1.2 million and $1.0 million, respectively, which was recorded in other comprehensive income. The related accumulated loss recorded by the Company in other comprehensive income (loss) as of December 31, 2016 is $5.9 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pursuant to a supply agreement that was signed in October 2013, the Company is supplying its OECs to the power plant and has added the $255.6 million supply contract to its Product Segment backlog. The Company started to recognize revenue from the project during the third quarter of 2014 and will continue to recognize revenue over the course of next year. The Company has eliminated the related intercompany profit of $12.0 million against equity in loss of investees.

During the year ended December 31, 2016, the Company made an additional cash equity investment contribution to the Sarulla project in the amount of $3.6 million.

NOTE 7 — VARIABLE INTEREST ENTITIES

The Company’s overall methodology for evaluating transactions and relationships under the variable interest entity (“VIE”) accounting and disclosure requirements includes the following two steps: (i) determining whether the entity meets the criteria to qualify as a VIE; and (ii) determining whether the Company is the primary beneficiary of the VIE.

In performing the first step, the significant factors and judgments that the Company considers in making the determination as to whether an entity is a VIE include:

• The design of the entity, including the nature of its risks and the purpose for which the entity was created, to determine the variability that the entity was designed to create and distribute to its interest holders;

• The nature of the Company’s involvement with the entity;

• Whether control of the entity may be achieved through arrangements that do not involve voting equity;

• Whether there is sufficient equity investment at risk to finance the activities of the entity; and

• Whether parties other than the equity holders have the obligation to absorb expected losses or the right to receive residual returns.

If the Company identifies a VIE based on the above considerations, it then performs the second step and evaluates whether it is the primary beneficiary of the VIE by considering the following significant factors and judgments:

• Whether the Company has the power to direct the activities of the VIE that most significantly impact the entity’s economic performance; and

• Whether the Company has the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

The Company’s VIEs include certain of its wholly owned subsidiaries that own one or more power plants with long-term PPAs. In most cases, the PPAs require the utility to purchase substantially all of the plant’s electrical output over a significant portion of its estimated useful life. Most of the VIEs have associated project financing debt that is non-recourse to the general creditors of the Company, is collateralized by substantially all of the assets of the VIE and those of its wholly owned subsidiaries (also VIEs) and is fully and unconditionally guaranteed by such subsidiaries. The Company has concluded that such entities are VIEs primarily because the entities do not have sufficient equity at risk and/or subordinated financial support is provided through the long-term PPAs. The Company has evaluated each of its VIEs to determine the primary beneficiary by considering the party that has the power to direct the most significant activities of the entity. Such activities include, among others, construction of the power plant, operations and maintenance, dispatch of electricity, financing and strategy. Except for power plants that it acquired, the Company is responsible for the construction of its power plants and generally provides operation and maintenance services. Primarily due to its involvement in these and other activities, the Company has concluded that it directs the most significant activities at each of its VIEs and, therefore, is considered the primary beneficiary. The Company performs an ongoing reassessment of the VIEs to determine the primary beneficiary and may be required to deconsolidate certain of its VIEs in the future. The Company has aggregated its consolidated VIEs into the following categories: (i) wholly owned subsidiaries with project debt; and (ii) wholly owned subsidiaries with PPAs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The tables below detail the assets and liabilities (excluding intercompany balances which are eliminated in consolidation) for the Company’s VIEs, combined by VIE classifications, that were included in the consolidated balance sheets as of December 31, 2016 and 2015:

	December 31, 2016
	Project Debt		PPAs
	(Dollars in thousands)
Assets:
Restricted cash and cash equivalents	$	34,262	$	—
Other current assets		157,351		7,482
Property, plant and equipment, net		1,305,254		177,970
Construction-in-process		48,128		72,725
Other long-term assets		24,802		—
Total assets	$	1,569,797	$	258,177
Liabilities:
Accounts payable and accrued expenses	$	10,900	$	3,992
Long-term debt		668,815		—
Other long-term liabilities		126,879		5,779
Total liabilities	$	806,594	$	9,771

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	December 31, 2015
	Project Debt		PPAs
	(Dollars in thousands)
Assets:
Restricted cash, cash equivalents and marketable securities	$	49,503	$	—
Other current assets		114,500		4,044
Property, plant and equipment, net		1,310,027		171,231
Construction-in-process		127,825		1,340
Other long-term assets		44,279		(1	)
Total assets	$	1,646,134	$	176,614
Liabilities:
Accounts payable and accrued expenses	$	11,404	$	2,931
Long-term debt		648,028		—
Other long-term liabilities		78,843		5,358
Total liabilities	$	738,275	$	8,289

NOTE 8— FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value measurement guidance clarifies that fair value is an exit price, representing the amount that would be received upon selling an asset or paid upon transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under the fair value measurement guidance are described below:

Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities;

Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability;

Level 3 — Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (supported by little or no market activity).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth certain fair value information at December 31, 2016 and 2015 for financial assets and liabilities measured at fair value by level within the fair value hierarchy, as well as cost or amortized cost. As required by the fair value measurement guidance, assets and liabilities are classified in their entirety based on the lowest level of inputs that is significant to the fair value measurement.

				December 31, 2016
				Fair Value
	Carrying Value at December 31, 2016			Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets:
Current assets:
Cash equivalents (including restricted cash accounts)	$	14,922		$	14,922		$	14,922	$	—		$	—
Derivatives:
Contingent receivable (1)		1,443			1,443			—		—			1,443
Liabilities:
Current liabilities:
Derivatives:
Contingent payables (1)		(11,581	)		(11,581	)		—		—			(11,581	)
Warrants (1)		(3,429	)		(3,429	)							(3,429	)
Currency forward contracts (2)		(481	)		(481	)		—		(481	)		—
	$	874		$	874		$	14,922	$	(481	)	$	(13,567	)

				December 31, 2015
				Fair Value
	Carrying Value at December 31, 2015			Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	31,428		$	31,428		$	31,428	$	—		$	—
Derivatives:
Currency forward contracts (2)		7			7			—		7			—
Liabilities:
Current liabilities:
Derivatives:
Currency forward contracts (2)		(169	)		(169	)		—		(169	)		—
	$	31,266		$	31,266		$	31,428	$	(162	)	$	—

⁽¹⁾   These amounts relate to contingent receivables and payables pertaining to the Guadeloupe power plant purchase transaction, valued primarily based on unobservable inputs and are included within "Prepaid expenses and other" and "Other long-term liabilities" on December 31, 2016 in the consolidated balance sheets with the corresponding gain or loss being recognized within "Derivatives and foreign currency transaction gains (losses)" in the consolidated statement of operations and comprehensive income.

⁽²⁾These amounts relate to derivatives which represent currency forward contracts valued primarily based on observable inputs, including forward and spot prices for currencies, netted against contracted rates and then multiplied against notional amounts, and are included within “prepaid expenses and other” and “accounts payable and accrued expenses” on December 31, 2016 and December 31, 2015, in the consolidated balance sheet with the corresponding gain or loss being recognized within “Derivatives and foreign currency transaction gains (losses)” in the consolidated statement of operations and comprehensive income.

The amounts set forth in the tables above include investments in debt instruments and money market funds (which are included in cash equivalents). Those securities and deposits are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices in an active market.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the amounts of gain (loss) recognized in the consolidated statements of operations and comprehensive income (loss) on derivative instruments not designated as hedges:

		Amount of recognized gain (loss)
Derivatives not designated as hedging instruments	Location of recognized gain (loss)	2016			2015			2014
		(Dollars in thousands)
Call options on natural gas price	Derivatives and foreign currency transaction gain (losses)	$	(1,340	)	$	—		$	—
Call and put options on oil price	Derivatives and foreign currency transaction gain (losses)		(1,313	)		—			—
Swap transaction on oil price	Electricity revenues		—			—			2,728
Swap transactions on natural gas price	Electricity revenues		—			1,158			2,996
Contingent considerations	Derivatives and foreign currency transaction gain (losses)		(1,527	)		—			—
Currency forward contracts	Derivatives and foreign currency transaction gain (losses)		238			(1,206	)		(4,949	)
		$	(3,942	)	$	(48	)	$	775

On September 3, 2013, the Company entered into a Natural Gas Index (“NGI”) swap contract with a bank covering a notional quantity of approximately 4.4 million British Thermal Units (“MMbtu”) for settlement effective January 1, 2014 until December 31, 2014, in order to reduce its exposure to fluctuations in natural gas prices under its Power Purchase Agreements (“PPAs”) with Southern California Edison to below $4.035 per MMbtu. The contract did not have up-front costs. Under the terms of this contract, the Company made floating rate payments to the bank and received fixed rate payments from the bank on each settlement date. The swap contract had a monthly settlement whereby the difference between the fixed price of $4.035 per MMbtu and the market price on the first commodity business day on which the relevant commodity reference price is published in the relevant calculation period (January 1, 2014 to December 1, 2014) was settled on a cash basis.

On October 16, 2013, the Company entered into an NGI swap contract with a bank covering a notional quantity of approximately 4.2 million MMbtu for settlement effective January 1, 2014 until December 31, 2014, in order to reduce its exposure to fluctuations in natural gas prices under its PPAs with Southern California Edison to below $4.103 per MMbtu. The contract did not have any up-front costs. Under the terms of this contract, the Company made floating rate payments to the bank and received fixed rate payments from the bank on each settlement date. The swap contract had a monthly settlement whereby the difference between the fixed price of $4.103 per MMbtu and the market price on the first commodity business day on which the relevant commodity reference price is published in the relevant calculation period (January 1, 2014 to December 1, 2014) was settled on a cash basis.

On October 16, 2013, the Company entered into a New York Harbor Ultra-Low Sulfur Diesel swap contract with a bank covering a notional quantity of 275,000 BBL effective from January 1, 2014 until December 31, 2014 to reduce the Company’s exposure to fluctuations in the energy rate caused by fluctuations in oil prices under the 25 MW PPA for the Puna complex. The Company entered into this contract because the swap had a high correlation with the avoided costs (which are incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others) that Hawaii Electric Light Company (“HELCO”) uses to calculate the energy rate. The contract did not have any up-front costs. Under the term of this contract, the Company made floating rate payments to the bank and received fixed rate payments from the bank on each settlement date ($125.15 per BBL). The swap contract had a monthly settlement whereby the difference between the fixed price of $125.15 per BBL and the monthly average market price was settled on a cash basis.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On March 6, 2014, and on May 14, 2015, the Company entered into NGI swap contracts with a bank covering a notional quantity of approximately 2.2 MMbtu for settlement effective January 1, 2015 until March 31, 2015, and covering a notional quantity of approximately 2.4 MMbtu for settlement effective June 1, 2015 until December 31, 2015, respectively, in order to reduce its exposure to fluctuations in natural gas prices under its PPAs with Southern California Edison to below $4.95 per MMbtu and below $3.00 per MMbtu, respectively. The contracts did not have any up-front costs. Under the terms of these contracts, the Company made, and will make, floating rate payments to the bank and received, and will receive, fixed rate payments from the bank on each settlement date. The swap contracts have monthly settlements whereby the difference between the fixed price and the market price on the first commodity business day on which the relevant commodity reference price is published in the relevant calculation period (January 1, 2015 to March 1, 2015 and June 1, 2015 to December 31, 2015) are settled on a cash basis.

On February 2, 2016, the Company entered into Henry Hub Natural Gas Future contracts under which it has written a number of call options covering a notional quantity of approximately 4.1 MMbtu with exercise prices of $2 and expiration dates ranging from February 24, 2016 until December 27, 2016 in order to reduce its exposure to fluctuations in natural gas prices under its PPAs with Southern California Edison. The Company received an aggregate premium of approximately $1.9 million from these call options. The call option contracts have monthly expiration dates at which the options can be called and the Company would have to settle its liability on a cash basis.

On February 24, 2016, the Company entered into Brent Oil Future contracts under which it has written a number of call options covering a notional quantity of approximately 185,000 barrels (“BBL”) of Brent with exercise prices of $32.80 to $35.50 and expiration dates ranging from March 24, 2016 until December 22, 2016 in order to reduce its exposure to fluctuations in Brent prices under its PPA with HELCO. The Company received an aggregate premium of approximately $1.1 million from these call options. The call option contracts have monthly expiration dates whereby the options can be called and the Company would have to settle its liability on a cash basis. Moreover, during March 2016, the Company rolled 2 existing call options covering a total notional quantity of 31,800 BBL of Brent in order to limit its exposure to $41 to $42.50 instead of $32.80 to $33.50. In addition, the Company entered into short risk reversal transactions (sell call and buy put options) by rolling existing call options covering notional quantities of 16,500 BBL and 17,000 BBL in order to limit its exposure from the outstanding call options originally entered into in February 2016 to a range of $28.50 to $37.50 and $28 to $38.50, respectively.

The foregoing future, forward and swap transactions have not been designated as hedge transactions and are marked to market with the corresponding gains or losses recognized within “Derivatives and foreign currency transaction gains (losses)” and “Electricity revenues” in the consolidated statements of operations and comprehensive income, respectively. The Company recognized a net loss from these transactions of $2.4 million, $1.2 million and $4.9 million in the years ended December 31, 2016, 2015 and 2014, respectively, under Derivatives and foreign currency transaction gains (losses), and a net gain of $1.2 million and $5.7 million, in the years ended December 31, 2015, and 2014, respectively, under Electricity revenues.

There were no transfers of assets or liabilities between Level 1, Level 2 and Level 3 during the year ended December 31, 2016.

The fair value of the Company’s long-term debt is as follows:

	Fair Value				Carrying Amount
	2016		2015		2016		2015
	(Dollars in millions)				(Dollars in millions)
Olkaria III Loan - DEG	$	16.3	$	24.2	$	15.8	$	23.7
Olkaria III Loan - OPIC		253.4		262.6		246.6		264.6
Olkaria IV Loan - DEG 2		50.9		—		50.0		—
Amatitlan Loan		37.3		41.7		36.8		40.3
Senior Secured Notes:
Ormat Funding Corp. ("OFC")	17.0			30.0		17.0		30.0
OrCal Geothermal Inc. ("OrCal")		37.4		43.8		35.2		43.3
OFC 2 LLC ("OFC 2")		249.0		231.1		247.2		262.0
Don A. Campbell 1 ("DAC1")		88.9		—		92.4		—
Senior Unsecured Bonds		200.1		264.5		204.3		250.0
Other long-term debt		10.4		6.7		11.2		6.7

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of OFC Senior Secured Notes was determined using observable market prices as these securities are traded. The fair value of all the long-term debt is determined by a valuation model, which is based on a conventional discounted cash flow methodology and utilizes assumptions of current borrowing rates.The fair value of revolving lines of credit is determined using a comparison of market-based price sources that are reflective of similar credit ratings to those of the Company.

The carrying value of other financial instruments, such as revolving lines of credit and deposits approximates fair value.

The following table presents the fair value of financial instruments as of December 31, 2016:

	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III - DEG	$	—	$	—	$	16.3	$	16.3
Olkaria III - OPIC		—		—		253.4		253.4
Olkaria IV - DEG 2		—		—		50.9		50.9
Amatitlan loan		—		37.3		—		37.3
Senior Secured Notes:
OFC		—		17.0		—		17.0
OrCal		—		—		37.4		37.4
OFC 2		—		—		249.0		249.0
Don A. Campbell 1 ("DAC1")		—		—		88.9		88.9
Senior unsecured bonds		—		—		200.1		200.1
Other long-term debt		—		3.3		7.1		10.4
Deposits		14.4		—		—		14.4

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the fair value of financial instruments as of December 31, 2015:

	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III Loan - DEG	$	—	$	—	$	24.2	$	24.2
Olkaria III Loan - OPIC		—		—		262.6		262.6
Amatitlan Loan		—		41.7		—		41.7
Senior Secured Notes:
OFC		—		30.0		—		30.0
OrCal		—		—		43.8		43.8
OFC 2		—		—		231.1		231.1
Senior unsecured bonds		—		—		264.5		264.5
Other long-term debt		—		6.7		—		6.7
Deposits		15.9		—		—		15.9

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9 — PROPERTY, PLANT AND EQUIPMENT AND CONSTRUCTION-IN-PROCESS

Property, plant and equipment

Property, plant and equipment, net, consist of the following:

	December 31,
	2016			2015
	(Dollars in thousands)
Land owned by the Company where the geothermal resource is located	$	31,904		$	31,465
Leasehold improvements		3,848			3,691
Machinery and equipment		152,821			133,457
Land, buildings and office equipment		28,634			29,247
Automobiles		11,161			7,782
Geothermal and recovered energy generation power plants, including geothermal wells and exploration and resource development costs:
United States of America, net of cash grants and impairment charges		1,658,195			1,637,081
Foreign countries		541,626			494,105
Asset retirement cost		8,669			7,961
		2,436,858			2,344,789
Less accumulated depreciation		(880,480	)		(785,454	)
Property, plant and equipment, net	$	1,556,378		$	1,559,335

Depreciation expense for the years ended December 31, 2016, 2015, and 2014 amounted to $94.8 million, $95.2 million and $87.9 million, respectively. Depreciation expense for the years ended December 31, 2016, 2015 and 2014 is net of the impact of the cash grant in the amount of $5.5 million, $5.5 million and $5.3 million, respectively.

U.S. Operations

The net book value of the property, plant and equipment, including construction-in-process, located in the United States was approximately $1,376.1 million and $1,335.0 million as of December 31, 2016 and 2015, respectively. These amounts as of December 31, 2016 and 2015 are net of cash grants in the amount of $138.7 million and $144.2 million, respectively.

Foreign Operations

The net book value of property, plant and equipment, including construction-in-process, located outside of the United States was approximately $487.0 million and $473.1 million as of December 31, 2016 and 2015, respectively.

The Company, through its wholly owned subsidiary, OrPower 4, Inc. (“OrPower 4”) owns and operates geothermal power plants in Kenya. The net book value of assets associated with the power plants was $315.0 million and $355.8 million as of December 31, 2016 and 2015, respectively. The Company sells the electricity produced by the power plants to Kenya Power and Lighting Co. Ltd. (“KPLC”) under a 20-year PPA.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company, through its wholly owned subsidiary, Orzunil I de Electricidad, Limitada (“Orzunil”), owns a power plant in Guatemala. On January 22, 2014, Orzunil signed an amendment to the PPA with Instituto Nacional de Electrificacion (“INDE”) a Guatemalan power utility for its Zunil geothermal power plant in Guatemala. The amendment extends the term of the PPA from 2019 to 2034. The PPA amendment also transfers operation and management responsibilities of the Zunil geothermal field from INDE to the Company for the term of the amended PPA in exchange for a tariff increase. Additionally, INDE exercised its right under the PPA to become a partner in the Zunil power plant with a 3% equity interest. The net book value of the assets related to the power plant was $12.2 million and $19.2 million at December 31, 2016 and 2015, respectively.

The Company, through its wholly owned subsidiary, Ortitlan, Limitada (“Ortitlan”), owns a power plant in Guatemala. The net book value of the assets related to the power plant was $40.3 million and $46.0 million at December 31, 2016 and 2015, respectively.

Construction-in-process

Construction-in-process consists of the following:

	December 31,
	2016		2015
	(Dollars in thousands)
Projects under exploration and development:
Up-front bonus lease costs	$	17,385	$	26,491
Exploration and development costs		36,359		35,726
Interest capitalized		703		703
		54,447		62,920
Projects under construction:
Up-front bonus lease costs		37,713		27,473
Drilling and construction costs		202,211		150,467
Interest capitalized		12,338		7,975
		252,262		185,915
Total	$	306,709	$	248,835

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Projects under Exploration and Development
	Up-front Bonus Lease Costs			Exploration and Development Costs			Interest Capitalized			Total
	(Dollars in thousands)
Balance at December 31, 2013	$	30,141		$	38,220		$	1,278		$	69,639
Cost incurred during the year		—			19,231			—			19,231
Write off of unsuccessful exploration costs		(3,523	)		(11,474	)		(442	)		(15,439	)
Balance at December 31, 2014		26,618			45,977			836			73,431
Cost incurred during the year		37			10,104			869			11,010
Write off of unsuccessful exploration costs		(164	)		(1,415	)		—			(1,579	)
Transfer of projects under exploration and development to projects under construction		—			(18,940	)		(1,002	)		(19,942	)
Balance at December 31, 2015		26,491			35,726			703			62,920
Cost incurred during the year		1,514			25,165			—			26,679
Write off of unsuccessful exploration costs		(380	)		(2,637	)		—			(3,017	)
Transfer of projects under exploration and development to projects under construction		(10,240	)		(21,895	)		—			(32,135	)
Balance at December 31, 2016	$	17,385		$	36,359		$	703		$	54,447

	Projects under Construction
	Up-front Bonus Lease Costs		Drilling and Construction Costs			Interest Capitalized			Total
	(Dollars in thousands)
Balance at December 31, 2013	$	27,473	$	184,766		$	6,948		$	219,187
Cost incurred during the year		—		132,597			3,206			135,803
Transfer of completed projects to property, plant and equipment		—		(105,126	)		(970	)		(106,096	)
Sale of property, plant and equipment		—		(24,692	)		(911	)		(25,603	)
Balance at December 31, 2014		27,473		187,545			8,273			223,291
Cost incurred during the year		—		140,977			3,556			144,533
Transfer of exploration and development projects to projects under construction		—		18,940			1,002			19,942
Transfer of completed projects to property, plant and equipment		—		(196,995	)		(4,856	)		(201,851	)
Sale of property, plant and equipment		—		—			—			—
Balance at December 31, 2015		27,473		150,467			7,975			185,915
Cost incurred during the year		—		116,247			6,510			122,757
Transfer of exploration and development projects to projects under construction		10,240		21,895			—			32,135
Transafer of completed projects to property, plant and equipment		—		(86,398	)		(2,147	)		(88,545	)
Balance at December 31, 2016	$	37,713	$	202,211		$	12,338		$	252,262

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10 — INTANGIBLE ASSETS AND GOODWILL

Intangible assets amounting to $52.8 million and $25.9 million consist mainly of the Company’s power purchase agreements (“PPAs”) acquired in business combinations, net of accumulated amortization of $42.8 million and $38.4 million as of December 31, 2016 and 2015, respectively. Amortization expense for the years ended December 31, 2016, 2015, and 2014 amounted to $4.4 million, $3.3 million, and $3.3 million, respectively. Additions of intangible assets for the years ended December 31, 2016, 2015 and 2014, amounted to $33.0 million, $0.5 million and $0, respectively. The addition to intangible assets in 2016 relates to the purchase of the Guadeloupe plant (Note 3). There were no disposals of intangible assets in 2016, 2015 and 2014.

Estimated future amortization expense for the intangible assets as of December 31, 2016 is as follows:

	(Dollars in thousands)
Year ending December 31:
2017	$	5,042
2018		4,912
2019		4,839
2020		4,522
2021		4,522
Thereafter		28,916
Total	$	52,753

Goodwill

Goodwill amounting to $7.1 million was recorded as a result of the Guadeloupe power plant purchase transaction that was closed in July 2016 (see Note 3 for more details). During 2016, there were no additions or adjustments to the carrying value of goodwill except for the impact of currency translation adjustments. The carrying value of goodwill as of December 31, 2016 is $6.7 million.

NOTE11 — ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses consist of the following:

	December 31,
	2016		2015
	(Dollars in thousands)
Trade payables	$	48,309	$	41,364
Salaries and other payroll costs		17,977		14,671
Customer advances		576		2,533
Accrued interest		3,524		8,252
Income tax payable		8,824		11,353
Property tax payable		1,884		3,609
Scheduling and transmission		964		1,547
Royalty accrual		1,639		1,818
Other		7,953		6,808
Total	$	91,650	$	91,955

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE12 — LONG-TERM DEBT AND CREDIT AGREEMENTS

Long-term debt consists of notes payable under the following agreements:

	December 31,
	2016			2015
	(Dollars in thousands)
Limited and non-recourse agreements:
Loans:
Non-recourse:
Other loans	$	6,368		$	-
Limited recourse:
Loan agreement with OPIC (the Olkaria III power plant)		246,630			264,624
Loan agreement with Banco Industrial S.A. and Westrust Bank (International) Limited		36,750			40,250
Senior Secured Notes:
Non-recourse:
Ormat Funding Corp. ("OFC")		17,026			29,968
OrCal Geothermal Inc. ("OrCal")		35,181			43,332
Don A. Campbell 1 ("DAC1")		92,361
Limited recourse:
OFC 2 LLC ("OFC 2")		247,232			261,959
		681,548			640,133
Less current portion		(53,729	)		(51,425	)
Non current portion	$	627,819		$	588,708
Full recourse agreements:
Senior unsecured bonds	$	204,332		$	249,981
Loans from institutional investors		3,333			6,667
Loan agreements with DEG (the Olkaria III and IV power plants)		65,789			23,684
Loan from a commercial bank		1,529			-
Revolving credit lines with banks		-			-
		274,983			280,332
Less current portion		(12,242	)		(11,229	)
Non current portion	$	262,741		$	269,103

Loan Agreement with Banco Industrial S.A. and Westrust Bank (International) Limited

On July 31, 2015, one of our indirect wholly-owned subsidiaries, Ortitlản, Limitada, obtained a 12-year secured term loan in the principal amount of $42.0 million for the 20 MW Amatitlan power plant in Guatemala. Under the credit agreement with Banco Industrial S.A. and Westrust Bank (International) Limited, we can expand the Amatitlan power plant with financing to be provided either via equity, additional debt from Banco Industrial S.A. or from other lenders, subject to certain limitations on expansion financing in the credit agreement.

The loan is payable in 48 quarterly payments commencing September 30, 2015. The loan bears interest at a rate per annum equal to of the sum of the LIBO Rate (which cannot be lower than 1.25%) plus a margin of (i) 4.35% as long as the Company’s guaranty of the loan (as described below) is outstanding or (ii) 4.75% otherwise. Interest is payable quarterly, on March 30, June 30, September 30 and December 30 of each year, on the stated maturity date of the loan and on any prepayment or payment of the loan. The loan must be prepaid on the occurrence of certain events, such as casualty, condemnation, asset sales and expansion financing not provided by the lenders under the credit agreement, among others. The loan may be voluntarily prepaid if certain conditions are satisfied, including payment of a premium (ranging from 100-50 basis points) if prepayment occurs prior to the eighth anniversary of the loan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

There are various restrictive covenants under the Amatitlan credit agreement. These include, among others, (i) a financial covenant to maintain a Debt Service Coverage Ratio (as defined in the credit agreement) of not less than 1.15 to 1.00 as of the last day of any fiscal quarter and (ii) limitations on Restricted Payments (as defined in the credit agreement) that among other things would limit dividends that could be paid to us unless the historical and projected Debt Service Coverage Ratio is not less than 1.25 to 1.00 for the four fiscal quarterly periods (calculated as a single accounting period). As of December 31, 2016, the actual historical and projected 12-month Debt Service Coverage Ratio was 1.87 and 1.92, respectively. The credit agreement includes various events of default that would permit acceleration of the loan (subject in some cases to grace and cure periods). These include, among others, a Change of Control (as defined in the credit agreement) and failure to maintain certain required balances in debt service and maintenance reserve accounts. The credit agreement includes certain equity cure rights for failure to maintain the Debt Service Coverage Ratio and the minimum amounts required in the debt service and maintenance reserve accounts.

The loan is secured by substantially all the assets of the borrower and a pledge of all of the membership interests of the borrower.

The Company has guaranteed payment of all obligations under the credit agreement and related financing documents. The guaranty is limited in the sense that the Company is only required to pay the guaranteed obligations if a “trigger event” occurs. A trigger event is the occurrence and continuation of a default by Instituto Nacional de Electricidad (“INDE”) in its payment obligations under the power purchase agreement for the Amatitlàn power plant or a refusal by INDE to receive capacity and energy sold under that power purchase agreement. Our obligations under the guaranty may be terminated prior to payment in full of the guaranteed obligations under certain circumstances described in the guaranty. If our guaranty is terminated early, the interest rate payable on the loan would increase as described above.

As of December 31, 2016, $36.8 million of this loan is outstanding.

Finance Agreement with OPIC (the Olkaria III Complex)

On August 23, 2012, the Company’s wholly owned subsidiary, OrPower 4 entered into a Finance Agreement with Overseas Private Investment Corporation (“OPIC”), an agency of the United States government, to provide limited-recourse senior secured debt financing in an aggregate principal amount of up to $310.0 million (the “OPIC Loan”) for the refinancing and financing of the Olkaria III geothermal power complex in Kenya. The Finance Agreement was amended on November 9, 2012.

The OPIC Loan is comprised of up to three tranches:

• Tranche I in an aggregate principal amount of $85.0 million, which was drawn in November 2012, was used to prepay approximately $20.5 million (plus associated prepayment penalty and breakage costs of $1.5 million) of the DEG Loan, as described below. The remainder of Tranche I proceeds was used for reimbursement of prior capital costs and other corporate purposes.

• Tranche II in an aggregate principal amount of $180.0 million was used to fund the construction and well field drilling for the expansion of the Olkaria III geothermal power complex (“Plant 2”). In November 2012, an amount of $135.0 million was disbursed under this Tranche II, and in February 2013, the remaining $45.0 million was distributed under this Tranche II.

• Tranche III in an aggregate principal amount of $45.0 million was used to fund the construction of Plant 3 of the Olkaria III complex. In November 2013, an amount of $45.0 million was disbursed under this Tranche.

In July 2013, we completed the conversion of the interest rate applicable to both Tranche I and Tranche II from a floating interest rate to a fixed interest rate. The average fixed interest rate for Tranche I, which has an outstanding balance as of December 31, 2016 of $66.0 million and matures on December 15, 2030, and Tranche II, which has an outstanding balance as of December 31, 2016 of $142.9 million and matures on June 15, 2030, is 6.31%. In November 2013, we fixed the interest rate for Tranche III. The fixed interest rate for Tranche III, which has an outstanding balance as of December 31, 2016 of $37.6 million and matures on December 15, 2030, is 6.12%.

OrPower 4 has a right to make voluntary prepayments of all or a portion of the OPIC Loan subject to prior notice, minimum prepayment amounts, and a prepayment premium of 2.0% in the first two years after the Plant 2 commercial operation date, declining to 1% in the third year after the Plant 2 commercial operation date, and without premium thereafter, plus a redemption premium. In addition, the OPIC Loan is subject to customary mandatory prepayment in the event of certain reductions in generation capacity of the power plants, unless such reductions will not cause the projected ratio of cash flow to debt service to fall below 1.7.

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The OPIC Loan is secured by substantially all of OrPower 4’s assets and by a pledge of all of the equity interests in OrPower 4.

The finance agreement includes customary events of default, including failure to pay any principal, interest or other amounts when due, failure to comply with covenants, breach of representations and warranties, non-payment or acceleration of other debt of OrPower 4, bankruptcy of OrPower 4 or certain of its affiliates, judgments rendered against OrPower 4, expropriation, change of control, and revocation or early termination of security documents or certain project-related agreements, subject to various exceptions and notice, cure and grace periods.

The repayment of the remaining outstanding DEG Loan (see “Full-Recourse Third-Party Debt” below) in the amount of approximately $15.8 million as of December 31, 2016, has been subordinated to the OPIC Loan.

There are various restrictive covenants under the OPIC Loan, which include a required historical and projected 12-month DSCR of not less than 1.4 (measured as of March 15, June 15, September 15 and December 15 of each year). If OrPower 4 fails to comply with these financial ratios it will be prohibited from making distributions to its shareholders. In addition, if the DSCR falls below 1.1, subject to certain cure rights, such failure will constitute an event of default by OrPower 4. This covenant in respect of Tranche I became effective on December 15, 2014. As of December 31, 2016, the actual historical and projected 12-month DSCR was 2.69 and 2.96, respectively.

As of December 31, 2016, $246.6 million of the OPIC Loan was outstanding.

Debt service reserve

As required under the terms of the OPIC Loan, OrPower 4 maintains an account which may be funded by cash or backed by letters of credit in an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the OPIC Loan in the following six months. This restricted cash account is classified as current in the consolidated balance sheets. As of December 31, 2016 and 2015, the balance of the account was $4.3 million and $7.2 million, respectively. In addition, as of December 31, 2016, part of the required debt service reserve was backed by a letter of credit in the amount of $17.3 million (see Note 23).

Well drilling reserve

As required under the terms of the OPIC Loan, OrPower 4 may be required to maintain an account which may be funded by cash or backed by letters of credit to reserve funds for future well drilling, based on determination upon the completion of the expansion work.

OFC Senior Secured Notes

In February 2004, OFC, a wholly owned subsidiary, issued $190.0 million of 8.25% Senior Secured Notes (“OFC Senior Secured Notes”) and received net cash proceeds of approximately $179.7 million, after deduction of issuance costs of approximately $10.3 million. The OFC Senior Secured Notes have a final maturity of December 30, 2020. Principal and interest on the OFC Senior Secured Notes are payable in semi-annual payments. The OFC Senior Secured Notes are collateralized by substantially all of the assets of OFC and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC. There are various restrictive covenants under the OFC Senior Secured Notes, which include limitations on additional indebtedness of OFC and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OFC.  In addition, there are restrictions on the ability of OFC to make distributions to its shareholders, which include a required historical and projected 12-month DSCR of not less than 1.25 (measured semi-annually as of June 30 and December 31 of each year). If OFC fails to comply with the DSCR ratio it will be prohibited from making distributions to its shareholders. The Company believes that the transition to variable energy prices under the Ormesa and Mammoth PPAs and the impact of the currently low natural gas prices on the revenues under these PPAs may cause OFC to not meet the DSCR ratio requirements for making distributions, but it does not believe that there will be an event of default by OFC. OFC is only required to measure these covenants on a semi-annual basis and as of December 31, 2016, the last measurement date of the covenants, the actual historical 12-month DSCR was 1.25 and the pro-forma 12-month DSCR was 1.38. There were $17.0 million and $30.0 million of OFC Senior Secured Notes outstanding as of December 31, 2016 and December 31, 2015, respectively.

In February 2013, the Company repurchased $12.8 million aggregate principal amount of OFC Senior Secured Notes from the OFC noteholders and recognized a gain of approximately $0.8 million in the first quarter of 2013.

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In January 2014, the Company repurchased $13.2 million aggregate principal amount of OFC Senior Secured Notes from the OFC noteholders and recognized a gain of approximately $0.3 million in the first quarter of 2014.

In June 2015, the Company repurchased $30.6 million aggregate principal amount of OFC Senior Secured Notes from the OFC noteholders and recognized a loss of approximately $1.7 million in the second quarter of 2015.

In September 2016, the Company repurchased $6.8 million aggregate principal amount of OFC Senior Secured Notes from the OFC noteholders and recognized a loss of $0.6 million, in the third quarter of 2016.

OFC may redeem the OFC Senior Secured Notes, in whole or in part, at any time, at redemption price equal to the principal amount of the OFC Senior Secured Notes to be redeemed plus accrued interest, premium and liquidated damages, if any, plus a “make-whole” premium. Upon certain events, as defined in the indenture governing the OFC Senior Secured Notes, OFC may be required to redeem a portion of the OFC Senior Secured Notes at a redemption price ranging from 100% to 101% of the principal amount of the OFC Senior Secured Notes being redeemed plus accrued interest, premium and liquidated damages, if any.

Debt service reserve

As required under the terms of the OFC Senior Secured Notes, OFC maintains an account which may be funded by cash or backed by letters of credit (see below) in an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the OFC Senior Secured Notes in the following six months. This restricted cash account is classified as current in the consolidated balance sheets. As of each of December 31, 2016 and 2015, the balance of such account was $2.1 million and $1.4 million, respectively. In addition, as of each of December 31, 2016 and 2015, part of the required debt service reserve was backed by a letter of credit in the amount of $11.5 million and $11.6 million (see Note 23), respectively.

OrCal Senior Secured Notes

In December 2005, OrCal, a wholly owned subsidiary, issued $165.0 million, 6.21% Senior Secured Notes (“OrCal Senior Secured Notes”) and received net cash proceeds of approximately $161.1 million, after deduction of issuance costs of approximately $3.9 million, which have been included in deferred financing costs in the consolidated balance sheet. The OrCal Senior Secured Notes have been rated BBB- by Fitch Ratings. The OrCal Senior Secured Notes have a final maturity of December 30, 2020. Principal and interest on the OrCal Senior Secured Notes are payable in semi-annual payments. The OrCal Senior Secured Notes are collateralized by substantially all of the assets of OrCal, and those of its subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OrCal. There are various restrictive covenants under the OrCal Senior Secured Notes, which include limitations on additional indebtedness of OrCal and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OrCal. In addition, there are restrictions on the ability of OrCal to make distributions to its shareholders, which include a required historical and projected 12-month DSCR of not less than 1.25 (measured semi-annually as of June 30 and December 31 of each year). If OrCal fails to comply with the DSCR ratio it will be prohibited from making distributions to its shareholders. OrCal is only required to measure these covenants on a semi-annual basis and as of December 31, 2016, the last measurement date of the covenants, the actual historical 12-month DSCR was 1.77 and the pro-forma 12-month DSCR was 2.57. There was $35.2 million and $43.3 million of OrCal Senior Secured Notes outstanding as of December 31, 2016 and December 31, 2015, respectively.

OrCal may redeem the OrCal Senior Secured Notes, in whole or in part, at any time at a redemption price equal to the principal amount of the OrCal Senior Secured Notes to be redeemed plus accrued interest, and a “make-whole” premium. Upon certain events, as defined in the indenture governing the OrCal Senior Secured Notes, OrCal may be required to redeem a portion of the OrCal Senior Secured Notes at a redemption price of 100% of the principal amount of the OrCal Senior Secured Notes being redeemed plus accrued interest.

Debt service reserve

As required under the terms of the OrCal Senior Secured Notes, OrCal maintains an account which may be funded by cash or backed by letters of credit (see below) in an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the OrCal Senior Secured Notes in the following six months. This restricted cash account is classified as current in the consolidated balance sheets. As of December 31, 2016 and 2015, the balance of such account was $1.9 million and $1.6 million, respectively. In addition, as of December 31, 2016 and 2015, part of the required debt service reserve was backed by a letter of credit in the amount of $4.6 million and $5.5 million, respectively (see Note 23).

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OFC 2 Senior Secured Notes

In September 2011, the Company’s subsidiary OFC 2 and its wholly owned project subsidiaries (collectively, the “OFC 2 Issuers”) entered into a note purchase agreement (the “Note Purchase Agreement”) with OFC 2 Noteholder Trust, as purchaser, John Hancock Life Insurance Company (U.S.A.), as administrative agent, and the DOE, as guarantor, in connection with the offer and sale of up to $350.0 million aggregate principal amount of OFC 2 Senior Secured Notes (“OFC 2 Senior Secured Notes”) due December 31, 2034.

Subject to the fulfillment of customary and other specified conditions precedent, the OFC 2 Senior Secured Notes may be issued in up to six distinct series associated with the phased construction (Phase I and Phase II) of the Jersey Valley, McGinness Hills and Tuscarora geothermal power plants, which are owned by the OFC 2 Issuers. The OFC 2 Senior Secured Notes will mature and the principal amount of the OFC 2 Senior Secured Notes will be payable in equal quarterly installments and in any event not later than December 31, 2034. Each series of notes will bear interest at a rate calculated based on a spread over the Treasury yield curve that will be set at least ten business days prior to the issuance of such series of notes. Interest will be payable quarterly in arrears. The DOE will guarantee payment of 80% of principal and interest on the OFC 2 Senior Secured Notes pursuant to Section 1705 of Title XVII of the Energy Policy Act of 2005, as amended. The conditions precedent to the issuance of the OFC 2 Senior Secured Notes includes certain specified conditions required by the DOE in connection with its guarantee of the OFC 2 Senior Secured Notes.

On October 31, 2011, the Issuers completed the sale of $151.7 million in aggregate principal amount of 4.687% Series A Notes due 2032 (the “Series A Notes”). The net proceeds from the sale of the Series A Notes, after deducting transaction fees and expenses, were approximately $141.1 million, and were used to finance a portion of the construction costs of Phase I of the McGinness Hills and Tuscarora power plants and to fund certain reserves. Principal and interest on the Series A Notes are payable quarterly in arrears on the last day of March, June, September and December of each year.

On June 20, 2014, Phase 1 of Tuscarora Facility achieved Project Completion under the OFC 2 Note Purchase Agreement. In accordance with the terms of the Note Purchase Agreement and following recalibration of the financing assumptions, the loan amount was adjusted through a principal prepayment of $4.3 million.

On August 29, 2014, OFC 2 signed a $140.0 million loan under the OFC 2 Senior Secured Notes to finance the construction of the McGinness Hills 2 Phase project. This drawdown is the last tranche (Series C notes) under the Note Purchase Agreement with John Hancock Life Insurance Company and guaranteed by the DOE’s Loan Programs Office in accordance with and subject to the DOE's Loan Guarantee Program under Section 1705 of Title XVII of the Energy Policy Act of 2005. The $140.0 million loan, which matures in December 2032, carries a 4.61% coupon with principal to be repaid on a quarterly basis. The OFC 2 Senior Secured Notes, which include loans for the Tuscarora, Jersey Valley and McGinness Hills complexes, are rated “BBB” by Standard & Poor's.

In connection with the anticipated drawdown, on August 13, 2014, the Company entered into an on-the-run interest rate lock agreement with a financial institution with a termination date of August 15, 2014. This on-the-run interest rate lock agreement had a notional amount of $140.0 million and was designated by us as a cash flow hedge. The objective of this cash flow hedge was to eliminate the variability in the changes in the 10-year U.S. Treasury rate as that is one of the components in the annual interest rate of the OFC 2 loan that was forecasted to be fixed on August 15, 2014. As such, the Company hedged the variability in total proceeds attributable to changes in the 10-year U.S. Treasury rate for the forecasted issuance of fixed rate OFC 2 loan. On August 18, 2014, the settlement date, the Company paid $1.5 million to the counterparty of the on-the-run interest rate lock agreement.

The Company concluded that the cash flow hedge was fully effective with no ineffective portion and no amounts excluded from the effectiveness testing, thus, in 2014, the total loss from the cash flow hedge was fully recognized in “Loss in respect of derivatives instruments designated for cash flow hedge” under other comprehensive income of $0.9 million noted above, which was net of related taxes of $0.6 million. The cash flow hedge loss recorded is amortized over the life of the OFC 2 loan using the effective interest method. In 2016 and 2015, the Company reclassified $0.1 million, each year, of the loss from “Accumulated other comprehensive income (loss)” into interest expense.

The OFC 2 Senior Secured Notes are collateralized by substantially all of the assets of OFC 2 and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC 2. There are various restrictive covenants under the OFC 2 Senior Secured Notes, which include limitations on additional indebtedness of OFC 2 and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OFC 2.  In addition, there are restrictions on the ability of OFC 2 to make distributions to its shareholders.

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Among other things, the distribution restrictions include a historical debt service coverage ratio requirement of at least 1.2 (on a blended basis for all OFC 2 power plants), measured, at the time of any proposed distribution, over each of the two six-months periods comprised of distinct consecutive fiscal quarters immediately preceding the proposed distribution, and a projected future debt service coverage ratio requirement of at least 1.5 (on a blended basis for all OFC 2 power plants), measured, at the time of any proposed distribution, over each of the two six-months periods comprised of distinct consecutive fiscal quarters immediately following such proposed distribution. As of December 31, 2016, our historical debt service coverage ratio was 2.49 and 2.09, respectively for each of the two six-month periods, and our projected future debt service coverage ratio was 1.98 and 2.05, respectively for each of the two six-month periods.

There were $247.2 million and $262.0 million of OFC 2 Senior Secured Notes outstanding as of December 31, 2016 and December 31, 2015, respectively.

The Company provided a guarantee in connection with the issuance of the Series A and C Notes. One trigger event is the failure of any facility financed by the relevant Series of OFC 2 Senior Secured Notes to reach completion and meet certain operational performance levels (the non-performance trigger) which gives rise to a prepayment obligation on the OFC 2 Senior Secured Notes. The other trigger event is a payment default on the OFC 2 Senior Secured Notes or the occurrence of certain fundamental defaults that result in the acceleration of the OFC 2 Senior Secured Notes, in each case that occurs prior to the date that the relevant facility(ies) financed by such OFC 2 Senior Secured Notes reaches completion and meets certain operational performance levels. A demand on the Company’s guarantee based on the non-performance trigger is limited to an amount equal to the prepayment amount on the OFC 2 Senior Secured Notes necessary to bring the OFC 2 Issuers into compliance with certain coverage ratios. A demand on the Company’s guarantee based on the other trigger event is not so limited.

Debt service reserve; other restricted funds

Under the terms of the OFC 2 Senior Secured Notes, OFC 2 is required to maintain a debt service reserve and certain other reserves, as follows:

(i) A debt service reserve account which may be funded by cash or backed by letters of credit (see below) in an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the OFC 2 Senior Secured Notes in the following six months. This restricted cash account is classified as current in the consolidated balance sheet. As of December 31, 2016, part of the required debt service reserve was backed by a letter of credit in the amount of $21.0 million (see Note 23).

(ii) A performance level reserve account, intended to provide additional security for the OFC 2 Senior Secured Notes, which may be funded by cash or backed by letters of credit. This reserve builds up over time and reduces gradually each time the project achieves certain milestones. Upon issuance of the Series A Notes, this reserve was funded in the amount of $28.0 million. As of December 31, 2016, the balance of such account was $9.7 million and there was no requirement for an additional letter of credit to be issued. 

(iii) Under the terms of the OFC 2 Senior Secured Notes, OFC 2 is also required to maintain a well field drilling and maintenance reserve that builds up over time and is dedicated to costs and expenses associated with drilling and maintenance of the project's well field, which may be funded by cash or backed by letters of credit.

(iv) A performance level reserve account for McGinness Hills Phase II, intended to provide additional security for the OFC 2 Senior Secured Notes, which may be funded by cash or backed by letters of credit. Upon issuance of the Series C Notes, this reserve was funded in the amount of $53.4 million in letter of credit. As of December 31, 2016, there was no requirement for an additional letter of credit to be issued.

Don A. Campbell Senior Secured Notes — Non-Recourse

On November 29, 2016, a Company subsidiary, ORNI 47 LLC (“ORNI 47”), entered into a note purchase agreement (the “Note Purchase Agreement”) with MUFG Union Bank, N.A., as collateral agent, Munich Reinsurance America, Inc. and Munich American Reassurance Company (the “Purchasers”) pursuant to which ORNI 47 issued and sold to the Purchasers $92.5 million aggregate principal amount of its 4.03% Senior Secured Notes due September 27, 2033 (the “Notes”) in a private placement exempt from the registration requirements of the Securities Act of 1933, as amended. ORNI 47 is the owner of the Don A. Campbell Phase I (“DAC 1”) geothermal power plant, and part of ORPD.

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The net proceeds from the sale of the Notes, after deducting certain transaction expenses and the funding of a debt service reserve account, were approximately $87.1 million and ORNI 47 intends to use the proceeds from the sale of the Notes to refinance the development and construction costs of the DAC 1 geothermal power plant, which were originally financed using equity.

ORNI 47 will pay a scheduled amount of principal of the Notes beginning on December 27, 2016 and then quarterly, on the 27th day of each March, June, September and December, until the Notes mature.

The Notes constitute senior secured obligations of ORNI 47 and are secured by all of the assets of ORNI 47. Under the Note Purchase Agreement, ORNI 47 may prepay at any time all, or from time to time any part of, the Notes in an amount equal to at least $2 million or such lesser amount as may remain outstanding under the Notes at 100% of the principal amount to be prepaid plus the applicable make-whole amount determined for the prepayment date with respect to such principal amount. Upon the occurrence of a Change of Control (as defined in the Note Purchase Agreement), ORNI 47 must make an offer to each holder of Notes to repurchase all of the holder’s Notes at 101% of the aggregate principal amount of Notes to be repurchased plus accrued and unpaid interest, if any, on the Notes to be repurchased to, but not including, the date of repurchase. Each holder of Notes may accept such offer in whole or in part. In certain events, including certain asset sales outside the ordinary course of business, ORNI 47 must make mandatory prepayments of the Notes at 100% of the principal amount to be prepaid. The Note Purchase Agreement requires ORNI 47 to comply with certain covenants, including, among others, restrictions on the incurrence of indebtedness or liens, amendment or modification of material project documents, the ability of ORNI 47 to merge or consolidate with another entity. The Note Purchase Agreement also contains customary events of default.  In addition, there are restrictions on the ability of ORNI 47 to make distributions to its shareholders, which include a required historical and projected Debt Service Coverage Ratio not less than 1.20 for the four fiscal quarterly periods. As of December 31, 2016, the projected Debt Service Coverage Ratio was 1.85.

As of December 31, 2016, $92.4 million is outstanding under the DAC 1 Loan.

Senior Unsecured Bonds

In August 2010, the Company entered into a trust instrument governing the issuance of, and accepted subscriptions for, an aggregate principal amount of approximately $142.0 million of senior unsecured bonds (the “Bonds”). Subject to early redemption, the principal of the Bonds was repayable in a single bullet payment upon the final maturity of the Bonds on August 1, 2017. The Bonds bore interest at a fixed rate of 7%, payable semi-annually. In February 2011, the Company accepted subscription for an aggregate principal amount of approximately $107.5 million of additional senior unsecured bonds (the “Additional Bonds”) under two addendums to the trust instrument. The terms and conditions of the Additional Bonds were identical to the original Bonds. The Additional Bonds were issued at a premium which reflects an effective fixed interest of 6.75%.

In September 2016, the Company concluded an auction tender and accepted subscriptions for $204 million aggregate principal amount of two tranches (Series 2 approximately $67 million and Series 3 approximately $137 million) of senior unsecured bonds. The proceeds from the senior unsecured bonds were used on September 29, 2016, to prepay the Company’s $250 million senior secured bonds that were payable on August 1, 2017.

The senior unsecured bonds, which were issued on September 14, 2016, have an outstanding aggregate principal amount of approximately $204.0 million consisting of two tranches (approximately $67 million principal amount of Series 2 and approximately $137 million principal amount of Series 3). The Series 2 Bonds will mature in September 2020 and bear interest at a fixed rate of 3.7% per annum, payable semi-annually. The Series 3 Bonds will mature in September 2022 and bear interest at a fixed rate of 4.45% per annum, payable semi-annually. The Bonds will be repaid at maturity in a single bullet payment, unless earlier prepaid by Ormat pursuant to the terms and conditions of the trust instrument that governs the Bonds. Both tranches received a rating of ilA+ from Maloot S&P in Israel with a stable outlook.

Loans from institutional investors

In July 2009, the Company entered into a 6-year loan agreement of $20.0 million with a group of institutional investors (the “First Loan”). The First Loan matured on July 16, 2015, was payable in 12 semi-annual installments, which commenced on January 16, 2010, and bore interest of 6.5%. As of December 31, 2015, this loan was fully repaid.

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In July 2009, the Company entered into an 8-year loan agreement of $20.0 million with another group of institutional investors (the “Second Loan”). The Second Loan matures on August 1, 2017, is payable in 12 semi-annual installments, which commenced on February 1, 2012, and bears interest at 6-month LIBOR plus 5.0%. As of December 31, 2016, $3.3 million was outstanding under this loan.

In November 2010, the Company entered into a 6-year loan agreement of $20.0 million with a group of institutional investors (the “Third Loan”). The Third Loan maturity date was November 16, 2016, was payable in ten semi-annual installments, which commenced on May 16, 2012, and bore interest of 5.75%. In October 2015, the Company prepaid this term loan in full and in accordance with the loan’s prepayment provisions. The total prepayment amount was $6.2 million comprising principal and interest.

Loan Agreements with DEG (the Olkaria III Complex)

In March 2009, the Company’s wholly owned subsidiary, OrPower 4, entered into a project financing loan of $105.0 million to refinance its investment in Phase I of the Olkaria III complex located in Kenya (the “DEG Loan”). The DEG Loan was provided by a group of European Development Finance Institutions (“DFIs”) arranged by DEG — Deutsche Investitions — und Entwicklungsgesellschaft mbH (“DEG”). The first disbursement of $90.0 million occurred on March 23, 2009 and the second disbursement of $15.0 million occurred on July 10, 2009. The DEG Loan will mature on December 15, 2018, and is payable in 19 equal semi-annual installments, commencing December 15, 2009. Interest on the DEG Loan is variable based on 6-month LIBOR plus 4.0% and OrPower 4 had the option to fix the interest rate upon each disbursement. Upon the first disbursement, the Company fixed the interest rate on $77.0 million of the DEG Loan at 6.90%. As of December 31, 2016, $15.8 million is outstanding under the DEG Loan (out of which $10.8 million bears interest at a fixed rate).

In October 2012, OrPower 4, DEG and the parties thereto amended and restated the DEG Loan agreement (the “DEG Amendment”). The DEG Amendment became effective on November 9, 2012 upon the execution by OrPower 4 of the Tranche I and Tranche II Notes and the related disbursements of the proceeds thereof under the OPIC Finance Agreement (as described above). The amended and restated DEG Loan Agreement provides for: (i) the prepayment in full of two loans thereunder in the total principal amount of approximately $20.5 million; (ii) the release and discharge of all collateral security previously provided by OrPower 4 to the secured parties under the DEG Loan agreement and the substitution of the Company’s guarantee of OrPower 4’s payment and certain other performance obligations in lieu thereof; and (iii) the establishment of a LIBOR floor of 1.25% in respect of one of the loans under the DEG Loan agreement, and (iv) the elimination of most of the affirmative and negative covenants under the DEG Loan agreement and certain other conforming provisions to take into account OrPower 4’s execution of the OPIC Finance Agreement and its obligations thereunder.

On October 20, 2016, OrPower 4 entered into a new $50 million subordinated facility agreement with DEG (the “DEG 2 Facility Agreement”) and on December 21, 2016, OrPower 4 completed a drawdown of the full loan amount of $50 million, with a fixed interest rate of 6.28% for the duration of the loan (the “DEG 2 Loan”). The DEG 2 Loan will be repaid in 20 equal semi-annual principal installments commencing December 21, 2018, with a final maturity on June 21, 2028. The DEG 2 Loan is intended for the refinance of Plant 4 of the Olkaria III Complex, which was originally financed using equity and is subordinated to the senior loan provided by OPIC for Plants 1-3 of the complex. The loan is guaranteed by the Company.

Under the DEG 2 Facility Agreement, OrPower 4 may prepay at any time all, or from time to time any part of the DEG 2 Loan in an amount equal to at least $5 million or such lesser amount as may remain outstanding under the DEG 2 Loan at 100% of the principal amount to be prepaid plus the applicable make-whole amount and certain prepayment premium amount determined for the prepayment date with respect to such principal amount. In certain events, OrPower 4 must make mandatory prepayments of the DEG 2 Loan at 100% of the principal amount to be prepaid plus the applicable make-whole amount and certain prepayment premium amount determined for the prepayment date with respect to such principal amount. The DEG 2 Facility Agreement requires OrPower 4 to comply with certain covenants, including, among others, restrictions on the incurrence of indebtedness or liens. The Facility Agreement also contains customary events of default.

As of December 31, 2016, $50.0 million is outstanding under the DEG 2 Loan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Revolving credit lines with commercial banks

As of December 31, 2016, the Company has credit agreements with eight commercial banks for an aggregate amount of $524.8 million (including $60.0 million from Union Bank, N.A. (“Union Bank”) and $35.0 million from HSBC), see below. Under the terms of these credit agreements, the Company, or its Israeli subsidiary, Ormat Systems, can request: (i) extensions of credit in the form of loans and/or the issuance of one or more letters of credit in the amount of up to $215.0 million; and (ii) the issuance of one or more letters of credit in the amount of up to $309.8 million. The credit agreements mature between end of March, 2017 and July 2019. Loans and draws under the credit agreements or under any letters of credit will bear interest at the respective bank’s cost of funds plus a margin.

As of December 31, 2016, no loans were outstanding, and letters of credit with an aggregate stated amount of $341.6 million were issued and outstanding under such credit agreements.

Credit Agreements

Credit agreement with Union Bank

In February 2012, the Company’s wholly owned subsidiary, Ormat Nevada Inc. (“Ormat Nevada”), entered into an amended and restated credit agreement with Union Bank. Under the amended and restated agreement, the credit termination date was extended to February 7, 2014 (which was subsequently extended to March 31, 2014 pursuant to Amendment No. 1 to the agreement and then to June 30, 2017), and the aggregate amount available under the credit agreement was increased from $39.0 million to $60.0 million. The facility is limited to the issuance, extension, modification or amendment of letters of credit. Union Bank is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as parties thereto. In connection with this transaction, the Company entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which the Company agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured. There are various restrictive covenants under the credit agreement, which include a requirement to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) 12-month DSCR of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of December 31, 2016: (i) the actual 12-month debt to EBITDA ratio was 2.95; (ii) the 12-month DSCR was 2.54; and (iii) the distribution leverage ratio was 0.81. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of Union Bank. As of December 31, 2016, letters of credit in the aggregate amount of $32.6 million remain issued and outstanding under this credit agreement with Union Bank.

Credit agreement with HSBC

In May 2013, Ormat Nevada, entered into a credit agreement with HSBC Bank USA, N.A for one year with annual renewals. The current expiration date of the facility under this credit agreement is December 31, 2017. The aggregate amount available under the credit agreement was increased by $10 million to $35.0 million. This credit line is limited to the issuance, extension, modification or amendment of letters of credit and $10.0 million out of this credit line for working capital needs. HSBC is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as parties thereto. In connection with this transaction, we entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which we agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured. There are various restrictive covenants under the credit agreement, including a requirement to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) 12-month DSCR of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of December 31, 2016: (i) the actual 12-month debt to EBITDA ratio was 2.95; (ii) the 12-month DSCR was 2.54; and (iii) the distribution leverage ratio was 0.81. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of HSBC. As of December 31, 2016, letters of credit in the aggregate amount of $23.2 million remain issued and outstanding under this credit agreement.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Restrictive covenants

The Company’s obligations under the credit agreements, the loan agreements, and the trust instrument governing the bonds, described above, are unsecured, but are subject to a negative pledge in favor of the banks and the other lenders and certain other restrictive covenants. These include, among other things, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of our assets, or a change of control in our ownership structure. Some of the credit agreements, the term loan agreements, as well as the trust instrument contain cross-default provisions with respect to other material indebtedness owed by us to any third party. In some cases, the Company has agreed to maintain certain financial ratios, which are measured quarterly, such as: (i) equity of at least $600.0 million and in no event less than 25% of total assets; (ii) 12-month debt, net of cash, cash equivalents marketable securities and short-term bank deposits to Adjusted EBITDA ratio not to exceed 6; and (iii) dividend distribution not to exceed 35% of net income for that year. As of December 31, 2016: (i) total equity was $1,170.0 million and the actual equity to total assets ratio was 47.53%, and (ii) the 12-month debt, net of cash, cash equivalents marketable securities and short-term bank deposits to Adjusted EBITDA ratio was 2.32. During the year ended December 31, 2016, the Company distributed interim dividends in an aggregate amount of $25.7 million.

Future minimum payments

Future minimum payments under long-term obligations, excluding revolving credit lines with commercial banks, as of December 31, 2016 are as follows:

	(Dollars in thousands)
Year ending December 31:
2017	$	65,971
2018		64,805
2019		59,146
2020		126,870
2021		46,579
Thereafter		593,161
Total	$	956,532

NOTE 13 — PUNA POWER PLANT LEASE TRANSACTIONS

In 2005, the Company’s wholly owned subsidiary in Hawaii, Puna Geothermal Ventures (“PGV”), entered into transactions involving the original geothermal power plant of the Puna complex located on the Big Island (the “Puna Power Plant”).

Pursuant to a 31-year head lease (the “Head Lease”), PGV leased the Puna Power Plant to an unrelated company in return for prepaid lease payments in the total amount of $83.0 million (the “Deferred Lease Income”). The carrying value of the leased assets as of December 31, 2016 and 2015 amounted to $28.0 million and $30.7 million, net of accumulated depreciation of $32.9 million and $30.2 million, respectively. The unrelated company (the “Lessor”) simultaneously leased back the Puna Power Plant to PGV under a 23-year lease (the “Project Lease”). PGV’s rent obligations under the Project Lease will be paid solely from revenues generated by the Puna Power Plant under a PPA that PGV has with Hawaii Electric Light Company (“HELCO”). The Head Lease and the Project Lease are non-recourse lease obligations to the Company. PGV’s rights in the geothermal resource and the related PPA have not been leased to the Lessor as part of the Head Lease but are part of the Lessor’s security package.

The Head Lease and the Project Lease are being accounted for separately. Each was classified as an operating lease in accordance with the accounting standards for leases. The Deferred Lease Income is amortized into revenue, using the straight-line method, over the 31-year term of the Head Lease. Deferred transaction costs amounting to $4.2 million are being amortized, using the straight-line method, over the 23-year term of the Project Lease.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Future minimum lease payments under the Project Lease, as of December 31, 2016, are as follows:

	(Dollars in thousands)
Year ending December 31:
2017	$	8,747
2018		8,944
2019		6,018
2020		2,450
2021		1,723
Thereafter		2,740
Total	$	30,622

Depository accounts

As required under the terms of the lease agreements, there are certain reserve funds that need to be managed by the indenture trustee in accordance with certain balance requirements. Such reserve funds amounted to $2.9 million and $2.1 million as of December 31, 2016 and 2015, respectively, and were included in restricted cash accounts in the consolidated balance sheets and were classified as current as they were used for current payments.

Distribution account

PGV maintains an account to deposit its remaining cash, after making all of the necessary payments and transfers as provided for in the lease agreements, in order to make distributions to Ormat Nevada. The distributions are allowed only if PGV maintains various restrictive covenants under the lease agreements, which include limitations on additional indebtedness. As of December 31, 2016 and 2015, the balance of such account was $0.

NOTE 14 —TAX MONETIZATION TRANSACTIONS

OPAL TRANSACTION

On December 16, 2016, the Company’s wholly owned subsidiary Ormat Nevada Inc. (“Ormat Nevada”) entered into an equity contribution agreement (the “Equity Contribution Agreement”) with OrLeaf LLC (“OrLeaf”) and JPM Capital Corporation (“JPM”) with respect to Opal Geo LLC (“Opal Geo”). Also on December 16, 2016, OrLeaf, a newly formed limited liability company formed by Ormat Nevada and ORPD LLC, entered into an amended and restated limited liability company agreement of Opal Geo (the “LLC Agreement”) with JPM. The transactions contemplated by the Equity Contribution Agreement and LLC Agreement will allow the Company to monetize federal production tax credits (“PTCs”) and certain other tax benefits relating to the operation of five geothermal power plants located in Nevada.

In connection with the transactions contemplated by the Equity Contribution Agreement and the LLC Agreement, Ormat Nevada transferred its indirect ownership interest in the McGinness Hills (Phase I and Phase II), Tuscarora, Jersey Valley and Don A. Campbell Phase 2 (“DAC 2”) geothermal power plants to Opal Geo. Prior to such transfer, Ormat Nevada held an approximately 63.25% indirect ownership interest in DAC 2 through ORPD LLC, a joint venture between Ormat Nevada and Northleaf Geothermal Holdings LLC (“Northleaf”), an affiliate of Northleaf Capital Partners, and held, directly or indirectly, a 100% ownership interest in the remaining geothermal power plants that were transferred to Opal Geo.

Pursuant to the Equity Contribution Agreement, JPM contributed approximately $62.1 million to Opal Geo in exchange for 100% of the Class B Membership Interests of Opal Geo. JPM also agreed to make deferred capital contributions to Opal Geo based on the amount of electricity generated by the DAC 2 and McGinness Hills Phase II power plants which are eligible for the federal production tax credit. The Company expects the aggregate amount of JPM’s deferred capital contributions to equal approximately $21 million and to be paid over time covering the period through December 31, 2022.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Under the LLC Agreement, until December 31, 2022, OrLeaf will receive distributions of 97.5% of any distributable cash generated by operation of the power plants while JPM will receive distributions of 2.5% of any distributable cash generated by operation of the power plants. Unless JPM has already achieved its target internal rate of return on its investment in Opal Geo, from December 31, 2022 until JPM has achieved its target internal rate of return, JPM will receive 100% of any distributable cash generated by operation of the power plants. Thereafter, OrLeaf will receive distributions of 97.5%, and JPM will receive 2.5%, of any distributable cash generated by operation of the power plants.

Under the LLC Agreement, all items of Opal Geo income and loss, gain, deduction and credit (including the federal production tax credits relating to the operation of the two PTC eligible power plants) will be allocated, until JPM has achieved its target internal rate of return on its investment in Opal Geo (and for so long as the two PTC eligible power plants are generating PTCs), 99% to JPM and 1% to OrLeaf, or 5% to JPM and 95% to OrLeaf if PTCs are no longer available to either of the two PTC eligible power plants. Once JPM achieves its target internal rate of return, all items of Opal Geo income and loss, gain, deduction and credit will be allocated 5% to JPM and 95% to OrLeaf.

Under the LLC Agreement, OrLeaf, which owns 100% of the Class A Membership Interests in Opal Geo, will serve as the managing member of Opal Geo and control the day-to-day management of Opal Geo and its portfolio of five power plants. However, in certain limited circumstances (such as bankruptcy of Orleaf, fraud or gross negligence by OrLeaf) JPM may remove OrLeaf as the managing member of Opal Geo. JPM, as the Class B Member of Opal Geo, has consent and approval rights with respect to certain items that are designated as major decisions for Opal Geo and the five power plants. In addition, by virtue of certain provisions in OrLeaf’s own limited liability company agreement, and consistent with the ORPD LLC formation documents, Northleaf has similar consent and approval rights with respect to OrLeaf’s determination of major decisions pertaining to the DAC 2 power plant. In both cases, these major decisions are generally equivalent to customary minority protection rights. As a result, the Company’s wholly owned subsidiary, Ormat Nevada, which serves as the managing member of OrLeaf and as the managing member of ORPD LLC, will effectively retain the day-to-day control and management of Opal Geo and its portfolio of five power plants.

The LLC Agreement contains certain customary restrictions on transfer applicable to both OrLeaf and JPM with respect to their respective Membership Interests in Opal Geo, and also provides OrLeaf with a right of first offer in the event JPM desires to transfer any of its Class B Membership Interests, pursuant to which OrLeaf may purchase such Class B Membership Interests. The LLC Agreement also provides OrLeaf with the option to purchase all of the Class B Membership Interests on either December 31, 2022 or the date that is 9 years after the closing date under the Equity Contribution Agreement at a price equal to the greater of (i) the fair market value of the Class B Membership Interests as of the date of purchase (subject to certain adjustments) and (ii) $3 million.

Pursuant to the Equity Contribution Agreement, the Company has provided a guaranty for the benefit of JPM of certain of OrLeaf’s indemnification obligations to JPM under the LLC Agreement. In addition, Ormat Nevada also provided a guaranty for the benefit of JPM of all present and future payment and performance obligations of OrLeaf under the LLC Agreement and each ancillary document to which OrLeaf is a party.

Pursuant to the Equity Contribution Agreement, JPM contributed approximately $62.1 million to Opal Geo in exchange for 100% of the Class B Membership Interests of Opal Geo. The contribution was recorded as $3.7 million allocation to noncontrolling interests and $58.5 million allocation to liability associated with sale of tax benefits as described in Note 1. JPM also agreed to make deferred capital contributions to Opal Geo based on the amount of electricity generated by the DAC 2 and McGinness Hills Phase II power plants which are eligible for the federal production tax credit. 

OPC TRANSACTION

In June 2007, Ormat Nevada entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. (Morgan Stanley Geothermal LLC and Lehman-OPC LLC), under which those investors purchased, for cash, interests in a newly formed subsidiary of Ormat Nevada, OPC LLC (“OPC”), entitling the investors to certain tax benefits (such as production tax credits (“PTCs”) and accelerated depreciation) and distributable cash associated with four geothermal power plants.

The first closing under the agreements occurred in 2007 and covered the Company’s Desert Peak 2, Steamboat Hills, and Galena 2 power plants. The investors paid $71.8 million at the first closing. The second closing under the agreements occurred in 2008 and covered the Galena 3 power plant. The investors paid $63.0 million at the second closing.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Ormat Nevada continues to operate and maintain the power plants. Under the agreements, Ormat Nevada initially received all of the distributable cash flow generated by the power plants, while the investors received substantially all of the production tax credits and taxable income or loss (together, the “Economic Benefits”). Once Ormat Nevada recovered the capital that it has invested in the power plants, which occurred in the fourth quarter of 2010, the investors receive both the distributable cash flow and the Economic Benefits. The investors’ return is limited by the term of the transaction. Once the investors reach a target after-tax yield on their investment in OPC (the “OPC Flip Date”), Ormat Nevada will receive 95% of both distributable cash and taxable income, on a going forward basis. Following the OPC Flip Date, Ormat Nevada also has the option to buy out the investors’ remaining interest in OPC at the then-current fair market value or, if greater, the investors’ capital account balances in OPC. Should Ormat Nevada exercise this purchase option, it would thereupon revert to being sole owner of the power plants.

The Class B membership units are provided with a 5% residual economic interest in OPC. The 5% residual interest commences on achievement by the investors of a contractually stipulated return that triggers the OPC Flip Date. The actual OPC Flip Date is expected to occur in the second quarter of 2017. This residual 5% interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments. Cash is distributed each period in accordance with the cash allocation percentages stipulated in the agreements. Until the fourth quarter of 2010, Ormat Nevada was allocated the cash earnings in OPC and therefore, the amount allocated to the 5% residual interest represented the noncash loss of OPC which principally represented depreciation on the property, plant and equipment. As from the fourth quarter of 2010, the distributable cash is allocated to the Class B membership units. As a result of the acquisition by Ormat Nevada, on October 30, 2009, of all of the Class B membership units of OPC held by Lehman-OPC LLC (see below), the residual interest decreased to 3.5%. Such residual interest increased to 5% on February 3, 2011 when Ormat Nevada sold its Class B membership units to JPM Capital Corporation (“JPM”) (see below).

The Company’s voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. Through Ormat Nevada, the Company owns all of the Class A membership units, which represent 75% of the voting rights in OPC. The investors own all of the Class B membership units, which represent 25% of the voting rights in OPC. In the period from October 30, 2009 to February 3, 2011, the Company owned, through Ormat Nevada, all of the Class A membership units, which represented 75% of the voting rights in OPC, and 30% of the Class B membership units, which represented 7.5% of the voting rights of OPC. In total the Company had 82.5% of the voting rights in OPC as of December 31, 2010. In that period, the investors owned 70% of the Class B membership units, which represented 17.5% of the voting rights of OPC. Other than in respect of customary protective rights, all operational decisions in OPC are decided by the vote of a majority of the membership units. Following the OPC Flip Date, Ormat Nevada’s voting rights will increase to 95% and the investor’s voting rights will decrease to 5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the OPC Flip Date and therefore consolidates OPC.

On October 30, 2009, Ormat Nevada acquired from Lehman-OPC LLC all of the Class B membership units of OPC held by Lehman-OPC pursuant to a right of first offer for a price of $18.5 million. A substantial portion of the initial sale of the Class B membership units by Ormat Nevada was accounted for as a financing transaction. As a result, the repurchase of these interests at a discount resulted in a pre-tax gain of $13.3 million in the year ended December 31, 2009. In addition, an amount of approximately $1.1 million has been reclassified from noncontrolling interest to additional paid-in capital representing the 1.5% residual interest of Lehman-OPC’s Class B membership units.

On February 3, 2011, Ormat Nevada sold to JPM all of the Class B membership units of OPC that it had acquired on October 30, 2010 for a sale price of $24.9 million in cash. The Company did not record any gain from the sale of its Class B membership interests in OPC to JPM. A substantial portion of the Class B membership units are accounted for as a financing transaction. As a result, the majority of these proceeds were recorded as a liability. In addition, $2.3 million has been reclassified from additional paid-in capital to noncontrolling interest representing the 1.5% residual interest of JPM’s Class B membership units.

ORTP TRANSACTION

In January 2013, Ormat Nevada entered into agreements with JP Morgan (“JPM”) under which JPM purchased interests in a newly formed subsidiary of Ormat Nevada, ORTP, LLC (“ORTP”), entitling JPM to certain tax benefits (such as PTCs and accelerated depreciation) associated with certain geothermal power plants in California and Nevada.

Under the terms of the transaction, Ormat Nevada transferred the Heber complex, the Mammoth complex, the Ormesa complex, and the Steamboat 2 and 3, Burdette (Galena 1) and Brady power plants to ORTP, and sold class B membership units in ORTP to JPM. In connection with the closing, JPM paid approximately $35.7 million to Ormat Nevada and will make additional payments to Ormat Nevada of 25% of the value of PTCs generated by the portfolio over time. The additional payments were expected to be made until December 31, 2016 up to maximum amount of $11.0 million. In the first quarter of 2017 and 2016, the Company received $1.6 million and $2.0 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Ormat Nevada will continue to operate and maintain the power plants. Under the agreements, Ormat Nevada will initially receive all of the distributable cash flow generated by the power plants, while JPM will receive substantially all of PTCs and the taxable income or loss (together, the “Economic Benefits”). JPM’s return is limited by the terms of the transaction. Once JPM reaches a target after-tax yield on its investment in ORTP (the “ORTP Flip Date”), Ormat Nevada will receive 97.5% of the distributable cash and 95% of the taxable income, on a going forward basis. At any time during the twelve-month period after the end of the fiscal year in which the ORTP Flip Date occurs (but no earlier than the expiration of five years following the date that the last of the power plants was placed in service for purposes of federal income taxes), Ormat Nevada also has the option to buy out JPM’s remaining interest in ORTP at the then-current fair market value. If Ormat Nevada were to exercise this purchase option, it would become the sole owner of the power plants again.

The Class B membership units entitle the holder to 5.0% (allocation of income and loss) and 2.5% (allocation of cash) residual economic interests in ORTP. The 5.0% and 2.5% residual interests commence on achievement by JPM of a contractually stipulated return that triggers the ORTP Flip Date. The actual ORTP Flip Date is expected to occur in the second quarter of 2017. These residual 5.0% and 2.5% interests represent noncontrolling interests and are not subject to mandatory redemption or guaranteed payments.

The Company’s voting rights in ORTP are based on a capital structure that is comprised of Class A and Class B membership units. Through Ormat Nevada the Company owns all of the Class A membership units, which represent 75% of the voting rights in ORTP. JPM owns all of the Class B membership units, which represent 25% of the voting rights of ORTP. Other than in respect of customary protective rights, all operational decisions in ORTP are decided by the vote of a majority of the membership units. Ormat Nevada retains the controlling voting interest in ORTP both before and after the ORTP Flip Date and therefore will continue to consolidate ORTP.

NOTE15 — ASSET RETIREMENT OBLIGATION

The following table presents a reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligation for the years presented below:

	Year Ended December 31,
	2016		2015
	(Dollars in thousands)
Balance at beginning of year	$	20,856	$	19,142
Revision in estimated cash flows		303		(681	)
Liabilities incurred		540		859
Accretion expense		1,649		1,536
Balance at end of year	$	23,348	$	20,856

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 16 — STOCK-BASED COMPENSATION

The Company makes an estimate of expected forfeitures and recognizes compensation costs only for those stock-based awards expected to vest. As of December 31, 2016, the total future compensation cost related to unvested stock-based awards that are expected to vest is $11.3 million, which will be recognized over a weighted average period of 1.4 years.

During the years ended December 31, 2016, 2015 and 2014, the Company recorded compensation related to stock-based awards as follows:

	Year Ended December 31,
	2016		2015		2014
	(Dollars in thousands, except per share data)
Cost of revenues	$	2,400	$	1,753	$	3,076
Selling and marketing expenses		247		123		261
General and administrative expenses		2,510		2,079		2,234
Total stock-based compensation expense		5,157		3,955		5,571
Tax effect on stock-based compensation expense		617		440		836
Net effect of stock-based compensation expense	$	4,540	$	3,515	$	4,735

During the fourth quarters of 2016, 2015 and 2014, the Company evaluated the trends in the stock-based award forfeiture rate and determined that the actual rates are 10.3%, 9.66% and 8.02%, respectively. This represents an increase of 7%, 20% and 12%, respectively, from prior estimates. As a result of the change in the estimated forfeiture rate, there was an immaterial impact on stock-based compensation expense in the respective periods.

Valuation assumptions

Prior to 2016, the fair value of each grant of stock-based awards was estimated using the Black-Scholes valuation model and the assumptions noted in the following table. The Company’s expected term represented the period that the Company’s stock-based awards were expected to be outstanding. In the absence of enough historical information, the expected term was determined using the simplified method giving consideration to the contractual term and vesting schedule. In 2016, The Company estimated the fair value of the stock-based awards using the Excercise Multiple-Based Lattice Model as it enables a degree of accounting for the complexities of option valuation and reduces the probability of a measurement error. The dividend yield forecast is expected to be 20% of the Company’s yearly net profit, which is equivalent to a 1.1% yearly weighted average dividend rate in the year ended December 31, 2016. The risk-free interest rate was based on the yield from U.S. constant treasury maturities bonds with an equivalent term. The forfeiture rate is based on trends in actual stock-based awards forfeitures.

The Company calculated the fair value of each stock-based award on the date of grant based on the following assumptions:

	Year Ended December 31,
	2016			2015			2014
For stock options issued by the Company:
Risk-free interest rates		1.3	%		1.4	%		1.7	%
Expected lives (in years)		4.5			4.0			5.1
Dividend yield		1.1	%		0.7	%		0.9	%
Expected volatility		30.7	%		29.2	%		35.1	%
Forfeiture rate (weighted average)		8.4	%		0	%		0	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock-based awards

The 2004 Incentive Compensation Plan

In 2004, the Company’s Board of Directors adopted the 2004 Incentive Compensation Plan (“2004 Incentive Plan”), which provides for the grant of the following types of awards: incentive stock options, non-qualified stock options, restricted stock, stock appreciation rights (“SARs”), stock units, performance awards, phantom stock, incentive bonuses, and other possible related dividend equivalents to employees of the Company, directors and independent contractors. Under the 2004 Incentive Plan, a total of 3,750,000 shares of the Company’s common stock have been reserved for issuance, all of which could be issued as options or as other forms of awards. Options and SARs granted to employees under the 2004 Incentive Plan cliff vest and are exercisable from the grant date as follows: 25% after 24 months, 25% after 36 months, and the remaining 50% after 48 months. Options granted to non-employee directors under the 2004 Incentive Plan cliff vest and are exercisable one year after the grant date. Vested shares may be exercised for up to ten years from the date of grant. The shares of common stock will be issued upon exercise of options or SARs from the Company’s authorized share capital. The 2004 Incentive Plan expired in May 2012 upon adoption of the 2012 Incentive Plan, except as to share based awards outstanding on that date.

The 2012 Incentive Compensation Plan

In May 2012, the Company’s shareholders adopted the 2012 Incentive Compensation Plan (“2012 Incentive Plan”), which provides for the grant of the following types of awards: incentive stock options, non-qualified stock options, restricted stock, SARs, stock units, performance awards, phantom stock, incentive bonuses, and other possible related dividend equivalents to employees of the Company, directors and independent contractors. Under the 2012 Incentive Plan, a total of 4,000,000 shares of the Company’s common stock have been reserved for issuance, all of which could be issued as options or as other forms of awards. Options and SARs granted to employees under the 2012 Incentive Plan will vest and become exercisable as follows: 25% vest 24 months after the grant date, an additional 25% vest 36 months after the grant date, and the remaining 50% vest 48 months after the grant date. Options granted to non-employee directors under the 2012 Incentive Plan will vest and become exercisable one year after the grant date. Vested stock-based awards may be exercised for up to ten years from the date of grant. The shares of common stock will be issued upon exercise of options or SARs from the Company’s authorized share capital.

The 2012 Incentive Plan empowers our Board of Directors, in its discretion, to amend the 2012 Incentive Plan in certain respects. Consistent with its authority to amend the Incentive Plan, in February 2014 the Board adopted and approved certain amendments to the 2012 Incentive Plan. The key amendments are as follows:

Increase of per grant limit: Section 15(a) of the 2012 Incentive Plan was amended to allow the grant of up to 400,000 shares of our common stock with respect to the initial grant of an equity award to newly hired executive officers in any calendar year. This amendment was adopted by our stockholders on May 31, 2014; and

Acceleration of vesting: Section 15(l) of the 2012 Incentive Plan was amended to clarify our ability to provide in the applicable award agreement that part and/or all of the award will be accelerated upon the occurrence of certain pre-determined events and/or conditions, such as a "change in control" (as defined in the 2012 Incentive Plan, as amended).

On February 11, 2014, the Company granted its Chief Financial Officer options to purchase 32,500 shares of common stock under the 2012 Incentive Plan. The exercise price of each option is $24.57, which represented the fair market value of the Company’s common stock on the grant date. Such options will expire five years from the date of grant and will vest in equal annual installments over a period of three years from the grant date, subject to acceleration upon a change of control.

The fair value of each stock option on the grant date was $5.78. The Company calculated the fair value of each stock option on the date of grant using the Black-Scholes valuation model based on the following assumptions:

Risk-free interest rates	0.81	%
Expected life (in years)	3.375
Dividend yield	0.80	%
Expected volatility	33.50	%
Forfeiture rate	0.00	%

On April 2, 2014, the Company granted its newly appointed Chief Executive Officer options to purchase up to an aggregate of 400,000 shares of common stock under the 2012 Incentive Plan. The exercise price of each option is $29.52 per share, which represented the fair market value of the Company’s common stock on the date of the grant. Options to purchase 300,000 shares of common stock will expire six years following the date of grant and will vest in equal annual installments over four years from the grant date, subject to acceleration in the event of a change of control. The remaining options to purchase 100,000 shares of common stock will vest on March 31, 2021, subject to acceleration associated with a change of control, and will expire seven and a half years from the date of grant.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of each option on the grant date was $12.88 for grant of options to purchase 300,000 shares of common stock, and $8.33 for the grant of options to purchase 100,000 shares of common stock. The Company calculated the fair value of each stock option on the date of grant using the Black-Scholes valuation model based on the following assumptions:

	Grant of options to purchase 300,000 shares of common stock			Grant of options to purchase 100,000 shares of common stock
Risk-free interest rates		2.36	%		1.64	%
Expected life (in years)		7.25			4.75
Dividend yield		0.90	%		0.90	%
Expected volatility		42.80	%		33.10	%

On November 5, 2014, the Company granted its directors options to purchase 52,500 shares of common stock under the 2012 Incentive Plan. The exercise price of each option is $28.23, which represented the fair market value of the Company’s common stock on the grant date. Such options will expire seven years from the date of grant and will fully vest one year from the grant date.

The fair value of each stock option on the grant date was $7.01. The Company calculated the fair value of each stock option on the date of grant using the Black-Scholes valuation model based on the following assumptions:

Risk-free interest rates	1.30	%
Expected life (in years)	4.0
Dividend yield	0.70	%
Expected volatility	32.40	%
Forfeiture rate	0.00	%

On November 3, 2015, the Company granted its directors options to purchase 45,000 shares of common stock under the 2012 Incentive Plan. The exercise price of each option is $38.24, which represented the fair market value of the Company’s common stock on the grant date. Such options will expire seven years from the date of grant and will fully vest one year from the grant date.

The fair value of each stock option on the grant date was $8.68. The Company calculated the fair value of each stock option on the date of grant using the Black-Scholes valuation model based on the following assumptions:

Risk-free interest rates	1.35	%
Expected life (in years)	4.0
Dividend yield	0.70	%
Expected volatility	29.20	%
Forfeiture rate	0.00	%

On June 13, 2016, the Company granted its employees, in aggregated 1,080,000 SAR under the Company’s 2012 Incentive Plan. The exercise price of each SAR is $42.87, which represented the fair market value of the Company’s common stock on the grant date. Such SARs will expire six years from the date of the grant and will vest over 4 years as follows: 50% after two years; an additional 25% after three years and the remaining 25% after four years from the grant date.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of each SAR on the grant date was $11.98 for senior management and $11.42 for other employees. The Company calculated the fair value of each SAR on the grant date using the Exercise Multiple-Based Lattice SAR-Pricing model based on the following assumptions:

Risk-free interest rate	1.29	%
Expected life (in years)	6
Dividend yield	1.14
Expected volatility	30.7	%
Forfeiture rate:
Senior management	0.0	%
Other employees	10.5	%
Sub-Optimal Exercise Factor:
Senior management	2.5
Other employees	2.0

On November 8, 2016, the Company granted its directors, in aggregated 60,000 SAR’s under the Company’s 2012 Incentive Plan. The exercise price of each SAR is $47.46, which represented the fair market value of the Company’s common stock on the grant date. Such SARs will expire seven years from the date of the grant and will vest at the end of the first year from the grant date.

The fair value of each SAR on the grant date was $14.51. The Company calculated the fair value of each SAR on the grant date using the Exercise Multiple-Based Lattice SAR-Pricing model based on the following assumptions:

Risk-free interest rate	1.65	%
Expected life (in years)	7
Dividend yield	1.1
Expected volatility	30.6	%
Forfeiture rate:	0.0	%
Sub-Optimal Exercise Factor:	2.5

	Year Ended December 31,
	2016					2015					2014
	Shares (in thousands)			Weighted Average Exercise Price		Shares (in thousands)			Weighted Average Exercise Price		Shares (in thousands)			Weighted Average Exercise Price
Outstanding at beginning of year		2,438		$	25.38		4,477		$	27.48		4,710		$	28.23
Granted, at fair value:
Stock Options		1,155			43.01		45			38.24		485			29.05
SARs*		—			—		—			—		—			—
Exercised		(967	)		25.33		(1,589	)		26.77		(243	)		24.10
Forfeited		(57	)		24.12		(125	)		27.33		(116	)		23.20
Expired		(4	)		26.84		(370	)		45.78		(359	)		42.70
Outstanding at end of year		2,565			33.36		2,438			25.38		4,477			27.48
Options and SARs exercisable at end of year		557			25.22		858			26.75		2,106			31.25
Weighted-average fair value of options and SARs granted during the year				$	11.61				$	8.68				$	9.00

__________

* Upon exercise, SARs entitle the recipient to receive shares of common stock equal to the increase in value of the award between the grant date and the exercise date.

As of December 31, 2016, 1,058,150 shares of the Company’s common stock are available for future grants under the 2012 Incentive Plan. No shares of the Company’s common stock are available for future grants under the 2004 Incentive Plan as of such date.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about stock-based awards outstanding at December 31, 2016 (shares in thousands):

		Options Outstanding						Options Exercisable
Exercise Price		Number of Stock-based Awards Outstanding		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value		Number of Stock-based Awards Exercisable		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value
$	18.56		15		2.8	$	526		15		2.8	$	526
	19.69		15		2.6		509		15		2.6		509
	20.13		108		2.3		3,608		108		2.3		3,608
	20.54		53		2.3		1,761		28		2.3		934
	23.34		635		2.4		19,226		140		2.4		4,247
	24.57		9		2.1		269		1		2.1		33
	25.65		68		1.3		1,905		68		1.3		1,905
	26.70		15		3.8		404		15		3.8		404
	28.23		30		4.8		762		30		4.8		762
	29.52		400		3.6		9,640		75		3.6		1,807
	29.95		17		0.3		400		17		0.3		400
	35.15		15		6.1		277		-		-		-
	38.24		45		5.8		692		45		5.8		692
	42.87		1,080		5.5		11,610		-		-		-
	47.46		60		6.9		370		-		-		-
			2,565		4.1	$	51,959		557		2.7	$	15,827

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about stock-based awards outstanding at December 31, 2015 (shares in thousands):

		Options Outstanding						Options Exercisable
Exercise Price		Number of Stock-based Awards Outstanding		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value		Number of Stock-based Awards Exercisable		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value
$	18.56		15		3.8	$	269		15		3.8	$	269
	19.69		15		3.6		252		15		3.6		252
	20.13		326		3.3		5,327		69		3.3		1,135
	20.54		100		3.3		1,593		50		3.3		797
	23.34		938		3.4		12,315		126		3.4		1,655
	24.57		33		3.1		387		16		3.1		193
	25.65		135		2.3		1,462		135		2.3		1,462
	26.70		45		4.8		440		45		4.8		440
	26.84		64		0.2		618		64		0.2		618
	28.19		15		1.8		124		15		1.8		124
	28.23		45		5.8		371		45		5.8		371
	29.21		3		1.3		22		3		1.3		22
	29.52		400		4.6		2,780		-		-		-
	29.95		148		1.3		963		148		1.3		963
	34.13		96		0.3		225		96		0.3		225
	38.24		15		6.8		-		-		-		-
	38.50		15		0.8		-		15		0.8		-
			2,438		3.3	$	27,148		857		2.4	$	8,526

The aggregate intrinsic value in the above tables represents the total pretax intrinsic value, based on the Company’s stock price of $53.62 and $36.47 as of December 31, 2016 and 2015, respectively, which would have potentially been received by the stock-based award holders had all stock-based award holders exercised their stock-based award as of those dates. The total number of in-the-money stock-based awards exercisable as of December 31, 2016 and 2015 was 557,350 and 842,911, respectively.

The total pretax intrinsic value of options exercised during the year ended December 31, 2016 and 2015 was $18.0 million and $14.1 million, respectively, based on the average stock price of $43.99 and $35.64 during the years ended December 31, 2016 and 2015, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 17 — POWER PURCHASE AGREEMENTS

Substantially all of the Company’s electricity revenues are recognized pursuant to PPAs in the U.S. and in various foreign countries, including Kenya and Guatemala. These PPAs generally provide for the payment of energy payments or both energy and capacity payments through their respective terms which expire in varying periods from 2017 to 2036. Generally, capacity payments are calculated based on the amount of time that the power plants are available to generate electricity. The energy payments are calculated based on the amount of electrical energy delivered at a designated delivery point. The price terms are customary in the industry and include, among others, a fixed price, short-run avoided cost (“SRAC”) (the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others), and a fixed price with an escalation clause that includes the value for environmental attributes, known as renewable energy credits. Certain of the PPAs provide for bonus payments in the event that the Company is able to exceed certain target levels and potential payments by the Company if it fails to meet minimum target levels. One PPA gives the power purchaser or its designee the right of first refusal to acquire the geothermal power plants at fair market value. Upon satisfaction of certain conditions specified in this PPA, and subject to receipt of requisite approvals and negotiations between the parties, the Company has the right to demand that the power purchaser acquire the power plant at fair market value. The Company’s subsidiaries in Guatemala sell power at an agreed upon price subject to terms of a “take or pay” PPA.

Pursuant to the terms of certain of the PPAs, the Company may be required to make payments to the relevant power purchaser under certain conditions, such as shortfall in delivery of renewable energy and energy credits, and not meeting certain performance threshold requirements, as defined in the relevant PPA. The amount of payment required is dependent upon the level of shortfall in delivery or performance requirements and is recorded in the period the shortfall occurs. In addition, if the Company does not meet certain minimum performance requirements, the capacity of the power plant may be permanently reduced.

As discussed in Note 1, the Company assessed all PPAs agreed to, modified or acquired in business combinations on or after July 1, 2003, and evaluated whether such PPAs contained a lease element requiring lease accounting. Future lease revenues under PPAs which contain a lease element as of December 31, 2016 including the PPAs that provide for minimum production or performance guarantees are accounted for as contingent lease revenues as they are production-based payments and contingent on generation levels that are impacted by climatic variables that are inherently uncertain including geological conditions and ambient temperature.

The PPAs considered to be leases were also assessed for inclusion of embedded derivatives, which required that they be separately accounted for at fair value. However, none of such PPAs were determined to include embedded derivatives.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE18 — INTEREST EXPENSE, NET

The components of interest expense are as follows:

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Interest related to sale of tax benefits	$	9,349		$	9,620		$	12,413
Interest expense		61,327			67,032			75,447
Less — amount capitalized		(3,287	)		(4,075	)		(3,206	)
	$	67,389		$	72,577		$	84,654

NOTE 19 — INCOME TAXES

U.S. and foreign components of income (loss) from continuing operations, before income taxes and equity in income (losses) of investees consisted of:

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
U.S	$	(7,109	)	$	(236	)	$	(2,623	)
Non-U.S. (foreign)		148,197			113,835			88,459
	$	141,088		$	113,599		$	85,836

The components of the provision (benefit) for income taxes, net are as follows:

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Current:
Federal	$	—		$	51		$	—
State		(276	)		252			490
Foreign		14,040			19,175			13,983
	$	13,764		$	19,478		$	14,473
Deferred:
Foreign		18,073			(34,736	)		13,135
		18,073			(34,736	)		13,135
	$	31,837		$	(15,258	)	$	27,608

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The significant components of the deferred income tax expense (benefit) are as follows:

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Other deferred tax expense (exclusive of the effect of other components listed below)	$	(1,105	)	$	541		$	(18,424	)
Usage (benefit) of operating loss carryforwards - U.S.		(14,072	)		(30,596	)		7,764
Change in valuation allowance		16,411			(14,324	)		3,526
Change in foreign valuation allowance		—			(49,701	)		—
Change in foreign income tax		18,073			14,965			13,135
Change in lease transaction		—			(452	)		2,136
Change in tax monetization transaction		48,000			16,386			5,184
Change in depreciation		(55,462	)		28,370			9,431
Change in intangible drilling costs		10,227			10,335			(9,706	)
Change in production tax credits and alternative minimum tax credit		(11,659	)		610			89
Basis difference in partnership interests		7,660			(10,870	)		—
	$	18,073		$	(34,736	)	$	13,135

Reconciliation of the U.S. federal statutory tax rate to the Company’s effective income tax rate is as follows:

	Year Ended December 31,
	2016			2015			2014
U.S. federal statutory tax rate		35.0	%		35.0	%		35.0	%
Valuation allowance - U.S.		11.1			(1.4	)		(1.7	)
Valuation allowance - foreign		-			(43.8	)
Tax monetization		-			-			2.5
State income tax, net of federal benefit		(0.2	)		0.6			(0.7	)
Effect of foreign income tax, net		(14.1	)		(5.1	)		(4.9	)
Production tax credits		(8.3	)		(0.1	)		0.9
Subpart F income		0.3			1.3			1.4
Depletion		-			-			(1.1	)
Other, net		(1.3	)		-			0.8
Effective tax rate		22.5	%		(13.5)	%		32.2	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The net deferred tax assets and liabilities consist of the following:

	December 31,
	2016			2015
	(Dollars in thousands)
Deferred tax assets (liabilities):
Net foreign deferred taxes, primarily depreciation	$	(35,382	)	$	(32,654	)
Depreciation		148,419			87,943
Intangible drilling costs		(112,762	)		(102,013	)
Net capital loss carryforward - U.S.		117,924			103,850
Tax monetization transaction		(105,789	)		(80,478	)
Investment tax credits		1,341			1,341
Production tax credits		82,451			70,792
Stock options amortization		3,241			3,467
Basis difference in partnership interest		(24,462	)		(16,801	)
Accrued liabilities and other		(752	)		2,435
		74,229			37,882
Less - valuation allowance		(109,611	)		(70,536	)
Total	$	(35,382	)	$	(32,654	)

The following table presents a reconciliation of the beginning and ending valuation allowance:

	Year Ended December 31,
	2016		2015			2014
	(Dollars in thousands)
Balance at beginning of the year	$	70,536	$	111,280		$	114,806
Additions to (release of) valuation allowance		39,075		(40,744	)		(3,526	)
Balance at end of the year	$	109,611	$	70,536		$	111,280

At December 31, 2016, the Company had U.S. federal net operating loss (“NOL”) carryforwards of approximately $299.6 million and state NOL carryforwards of approximately $244.7 million, available to reduce future taxable income, which expire between 2029 and 2036 for federal NOLs and between 2018 and 2036 for state NOLs. The investment tax credits (“ITCs”) in the amount of $1.3 million at December 31, 2016 are available for a 20-year period and expire between 2022 and 2024. The Production Tax Credits (“PTCs”) in the amount of $82.5 million at December 31, 2016 are available for a 20-year period and expire between 2026 and 2036.

Realization of the deferred tax assets and tax credits is dependent on generating sufficient taxable income in appropriate jurisdictions prior to expiration of the NOL carryforwards and tax credits. Based upon available evidence of the Company’s ability to generate additional taxable income in the future and historical losses in prior years, a valuation allowance in the amount of $109.6 million and $70.5 million is recorded against the U.S. deferred tax assets as of December 31, 2016 and 2015, respectively, as it is more likely than not that the deferred tax assets will not be realized. The increase in valuation allowance is due to increases in investment tax credits and step-up in basis relating to the tax monetization transaction.

As more fully described in Note 3, On November 23, 2016, the Company closed a follow-on sale of 36.75% of equity interest in the second phase of the Don A. Campbell power plant, as a result of this sale, the Company will recognize $21.4 million of taxable income in 2016. Following the closing, DACII was contributed to the existing ORPD, as agreed upon under the ORPD agreement with Northleaf.

On December 16, 2016, upon the formation of Opal and Orleaf, Orleaf distributed $43.1 million to Ormat and $19 million to ORPD. Upon this distribution, Ormat will recognize taxable gain of $4.8 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In November 2015, the FASB issued Accounting Standards Update 2015-17, Balance Sheet Classification of Deferred Taxes (ASU 2015-17), effective in fiscal years beginning after December 15, 2016. The new guidance requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The Company has elected early adoption of the aforementioned Update in 2015. The Company has adopted the Update prospectively. As such, the deferred tax assets and liabilities in 2016 and 2015 are being presented as noncurrent on the balance sheet.

In March 2016, the FASB issued Accounting Standards Update 2016-09, Improvements to Employee Share-Based Payment Accounting (ASU 2016- 09), effective in fiscal years beginning after December 15, 2016 for public companies. In general, the new guidance allows entities to record all excess tax benefits and tax deficiencies as income tax benefit or expense in the income statement. The Company has not elected an early adoption of the aforementioned Update.

In October 2016, the FASB issued Accounting Standards Update 2016-16, Income Taxes on Intercompany Transfers (ASU 2016- 16), effective in fiscal years beginning after December 15, 2017 for public companies. In general, the new guidance provides that the seller and buyer will immediately recognize the current and deferred income tax consequences of the intercompany asset transfer. The Company has not elected an early adoption of the aforementioned Update.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the deferred taxes on the balance sheets as of the dates indicated:

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Current deferred tax assets	$	—		$	—		$	251
Current deferred tax liabilities		—			—			(975	)
Non-current deferred tax liabilities		(35,382	)		(32,654	)		(66,219	)
	$	(35,382	)	$	(32,654	)	$	(66,943	)

The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $367 million at December 31, 2016. It is the Company’s intention to reinvest undistributed earnings of its foreign subsidiaries and thereby indefinitely postpone their remittance. Accordingly, no provision has been made for foreign withholding taxes or U.S. income taxes which may become payable if undistributed earnings of foreign subsidiaries were paid as dividends to the Company. The additional taxes on that portion of undistributed earnings which is available for dividends are not practicably determinable.

The Company believes that based on our plans to increase the operations outside of the U.S., the cash generated from our operations outside of the U.S. will be reinvested outside of the U.S. and, accordingly, we do not currently plan to repatriate the funds we have designated as being permanently invested outside the U.S. If we change our plans, we may be required to accrue and pay U.S. taxes to repatriate these funds.

Uncertain tax positions

We are subject to income taxes in the U.S. (federal and state) and numerous foreign jurisdictions. Significant judgment is required in evaluating our tax positions and determining our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. We establish reserves for tax-related uncertainties based on estimates of whether, and the extent to which additional taxes will be due. These reserves are established when we believe that certain positions might be challenged despite our belief that our tax return positions are fully supportable. We adjust these reserves in light of changing facts and circumstances, such as the outcome of tax audits. The provision for income taxes includes the impact of reserve positions and changes to reserves that are considered probable.

At December 31, 2016 and 2015, there are $5.7 million and $10.4 million of unrecognized tax benefits that if recognized would affect the annual effective tax rate. Interest and penalties assessed by taxing authorities on an underpayment of income taxes are included as a component of income tax provision in the consolidated statements of operations and comprehensive income.

A reconciliation of our unrecognized tax benefits is as follows:

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Balance at beginning of year	$	10,385		$	7,511		$	4,950
Additions based on tax positions taken in prior years		675			(198	)		230
Additions based on tax positions taken in the current year		1,059			4,386			2,980
Reduction based on tax positions taken in prior years		(6,381	)		(1,314	)		(649	)
Balance at end of year	$	5,738		$	10,385		$	7,511

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company and its U.S. subsidiaries file consolidated income tax returns for federal and state purposes. As of December 31, 2016, the Company has not been subject to U.S. federal or state income tax examinations. The Company remains open to examination by the Internal Revenue Service for the years 2000-2016 and by local state jurisdictions for the years 2002-2016. These examinations may lead to ordinary course adjustments or proposed adjustments to our taxes or our net operating losses with respect to years under examination as well as subsequent periods.

The reduction of $6.4 million, $1.3 million and $0.6 million in 2016, 2015 and 2014, respectively, was due to the statute of limitations expiration on certain tax positions as well as Ormat System's tax settlement as detailed below. 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company’s foreign subsidiaries remain open to examination by the local income tax authorities in the following countries for the years indicated:

Israel	2015	—	2016
Kenya	2001	—	2016
Guatemala	2010	—	2016
Philippines	2010	—	2016
New Zealand	2011	—	2016

Management believes that the liability for unrecognized tax benefits is adequate for all open tax years based on its assessment of many factors, including among others, past experience and interpretations of local income tax regulations. This assessment relies on estimates and assumptions and may involve a series of complex judgments about future events. As a result, it is possible that federal, state and foreign tax examinations will result in assessments in future periods. To the extent any such assessments occur, the Company will adjust its liability for unrecognized tax benefits.

Tax benefits in the U.S.

The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies under the ARRA which has been extended by the Consolidated Appropriations Act, 2016 (CAA) until December 31, 2019. The Company is permitted to claim 30% of the eligible cost of each new geothermal power plant in the United States, which is placed in service before January 1, 2017, as an ITC against its federal income taxes. After this date, the ITC is reduced to 10%. Alternatively, the Company is permitted to claim a PTC, which in 2016 is 2.3 cents per kWh and which may be adjusted annually for inflation. The PTC may be claimed for ten years on the electricity output of new geothermal power plants that have commenced construction by December 31, 2016. The owner of the power plant must choose between the PTC and the 30% ITC described above. In either case, under current tax rules, any unused tax credit has a 1-year carry back and a 20-year carry forward. Whether the Company claims the PTC or the ITC, it is also permitted to depreciate most of the plant for tax purposes over five years on an accelerated basis, meaning that more of the cost may be deducted in the first few years than during the remainder of the depreciation period. If the Company claims the ITC, the Company’s “tax base” in the plant that it can recover through depreciation must be reduced by half of the ITC. If the Company claims the PTC, there is no reduction in the tax basis for depreciation. Companies that place qualifying renewable energy facilities in service, during 2009, 2010 or 2011, or that begin construction of qualifying renewable energy facilities during 2012, 2013, 2014 or 2015 and place them in service by December 31, 2016, may choose to apply for a cash grant from the U.S. Department of the Treasury (“U.S. Treasury”) in an amount equal to the ITC. Likewise, the tax base for depreciation will be reduced by 50% of the cash grant received. Under the ARRA revised by the CAA, the U.S. Treasury is instructed to pay the cash grant within 60 governmental business days of the application or the date on which the qualifying facility is placed in service.

Income taxes related to foreign operations

Guatemala — The enacted tax rate is 25%. Orzunil, a wholly owned subsidiary, was granted a benefit under a law which promotes development of renewable power sources. The law allows Orzunil to reduce the investment made in its geothermal power plant from income tax payable, which reduces the effective tax rate to zero. Ortitlan, another wholly owned subsidiary, was granted a tax exemption for a period of ten years ending August 2017. The effect of the tax exemption in the years ended December 31, 2016, 2015, and 2014 is $3.3 million, $3.6 million, and $1.9 million, respectively ($0.07, $0.08, and $0.04 per share of common stock, respectively).

Israel — The Company’s operations in Israel through its wholly owned Israeli subsidiary, Ormat Systems Ltd. (“Ormat Systems”), are taxed at the regular corporate tax rate of 25% in 2012, 25% in 2013, 26.5% in 2014 and 2015 and 25% in 2016 and thereafter. Ormat Systems received “Benefited Enterprise” status under Israel’s Law for Encouragement of Capital Investments, 1959 (the “Investment Law”), with respect to two of its investment programs. As a Benefited Enterprise, Ormat Systems was exempt from Israeli income taxes with respect to income derived from the first benefited investment for a period of two years that started in 2004, and thereafter such income was subject to reduced Israeli income tax rates which will not exceed 25% for an additional five years until 2010. Ormat Systems was also exempt from Israeli income taxes with respect to income derived from the second benefited investment for a period of two years that started in 2007, and thereafter such income is subject to reduced Israeli income tax rates which will not exceed 25% for an additional five years until 2013. These benefits are subject to certain conditions, including among other things, that all transactions between Ormat Systems and its affiliates are at arm’s length, and that the management and control of Ormat Systems will be from Israel during the whole period of the tax benefits. A change in control should be reported to the Israel Tax Authority in order to maintain the tax benefits. In January 2011, new legislation amending the Investment Law was enacted. Under the new legislation, a uniform rate of corporate tax would apply to all qualified income of certain industrial companies, as opposed to the current law’s incentives that are limited to income from a “Benefited Enterprise” during their benefits period. According to the amendment, the uniform tax rate applicable to the zone where the production facilities of Ormat Systems are located would be 15% in 2011 and 2012, 12.5% in 2013, and 16% in 2014 and thereafter. Under the transitory provisions of the new legislation, Ormat Systems had the option either to irrevocably comply with the new law while waiving benefits provided under the previous law or to continue to comply with the previous law during a transition period with the option to move from the previous law to the new law at any stage. Ormat Systems decided to irrevocably comply with the new law starting in 2011.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In November 2012, new legislation amending the Investment Law was enacted. Under the new legislation, companies that have retained earnings as of December 31, 2011 from Benefited Enterprises may elect by November 11, 2013 to pay a reduced corporate tax rate as set forth in the new legislation on such income and distribute a dividend from such income without being required to pay additional corporate tax with respect to such income.  Ormat Systems decided not to make such election.

Ormat Systems tax assessment for fiscal years 2010-2014 was finalized and settled in January 2017. The settlement resulted in no impact to income statement due to release of the related uncertain tax position liability.

Kenya - The Company’s operations in Kenya are taxed at the rate of 37.5%. On September 11, 2015, Kenya's Income Tax Act was amended pursuant to certain provisions of the recently adopted Finance Act, 2015. Among other matters, these amendments retain the enhanced investment deduction of 150% under Section 17B of the Income Tax Act, extend the period for deduction of tax losses from 5 years to 10 years under Sections 15(4) and 15(5) of the Income Tax Act, and amend the effective date from January 1, 2016 to January 1, 2015 under Sections 15(4) and 15(5) of the Income Tax Act. Previously, the Company had a valuation allowance for the additional 50% investment deduction reducing its deferred tax asset in Kenya as the utilization of the related tax losses was not probable within the original five year carryforward period. As a result of the change in legislation and the expected continued profitability during the extended carryforward period, the Company expects that it will be able to fully utilize the carryforward tax losses within the ten year period and as such released the valuation allowance in Kenya resulting in a $49.4 million of tax benefits in the year ended December 31, 2015.

During the fourth quarter of 2016, the Company determined that its income statement tax provision and deferred tax liabilities in Kenya in prior periods were overstated by approximately $4.7 million as a result of errors in the determination of the exchange rate impact used in the calculation of taxable income at its Kenya operations. The Company recorded an adjustment to reduce income tax expense and deferred tax liabilities by $4.7 million in the fourth quarter of 2016 to correct this matter. 

As previously reported by the Company, the Kenya Revenue Authority (“KRA”) conducted an audit related to the Company’s operations in Kenya for fiscal years 2012 - 2013. In January 2017, KRA concluded its audit for the subject period and issued a demand letter to the Company for additional tax payments of approximately $16.1 million, including interest and penalties. KRA’s assessment, among other points, rejected the Company's income tax deduction of 150% of its investment in geothermal well drilling during the relevant period, on the basis that such work falls under mining activities (and not geothermal activities) which have a different allowable deduction under the Kenya Income Tax Act. The KRA audit and assessment is not final and is subject to objection by the Company. The Company's operations in Kenya utilize a geothermal resource license from the Ministry of Energy and Petroleum. The Company does not conduct and is not involved in any mining activity under applicable Kenyan law. Therefore, the Company believes that its original tax position was and remains correct under Kenyan tax law and regulations, and has submitted a notice of objection to the KRA which it intends to pursue vigorously. If the KRA position prevails and is applied to subsequent periods, the Company's deferred tax asset of $49.4 million recorded in 2015 may be impacted. At present, the Company has recorded a provision based on its assessment of its reasonably expected potential exposure.

Other significant foreign countries — The Company’s operations in New Zealand are taxed at the rate of 28% in 2015, 2014 and 2013.

NOTE 20 — BUSINESS SEGMENTS

The Company has two reporting segments: the Electricity and Product segments. These segments are managed and reported separately as each offers different products and serves different markets. The Electricity segment is engaged in the sale of electricity from the Company’s power plants pursuant to PPAs. The Product segment is engaged in the manufacture, including design and development, of turbines and power units for the supply of electrical energy and in the associated construction of power plants utilizing the power units manufactured by the Company to supply energy from geothermal fields and other alternative energy sources. Transfer prices between the operating segments were determined on current market values or cost plus markup of the seller’s business segment.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summarized financial information concerning the Company’s reportable segments is shown in the following tables:

	Electricity		Product		Consolidated
	(Dollars in thousands)
Year Ended December 31, 2016:
Net revenues from external customers	$	436,292	$	226,299	$	662,591
Intersegment revenues		—		56,075		56,075
Depreciation and amortization expense		102,698		3,279		105,977
Operating income		126,828		75,054		201,882
Segment assets at period end		2,204,444		257,125		2,461,569
Expenditures for long-lived assets		147,211		4,719		151,930
Year Ended December 31, 2015:
Net revenues from external customers	$	375,920	$	218,724	$	594,644
Intersegment revenues		—		48,559		48,559
Depreciation and amortization expense		103,892		3,314		107,206
Operating income		99,345		64,716		164,061
Segment assets at period end		2,044,346		229,636		2,273,982
Expenditures for long-lived assets		149,666		2,784		152,450
Year Ended December 31, 2014 :
Net revenues from external customers	$	382,301	$	177,223	$	559,524
Intersegment revenues		—		44,718		44,718
Depreciation and amortization expense		97,826		2,973		100,799
Operating income		90,401		53,089		143,490
Segment assets at period end		1,963,486		158,070		2,121,556
Expenditures for long-lived assets		155,323		3,458		158,781

Reconciling information between reportable segments and the Company’s consolidated totals is shown in the following table:

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Revenues:
Total segment revenues	$	662,591		$	594,644		$	559,524
Intersegment revenues		56,075			48,559			44,718
Elimination of intersegment revenues		(56,075	)		(48,559	)		(44,718	)
Total consolidated revenues	$	662,591		$	594,644		$	559,524
Operating income:
Operating income	$	201,882		$	164,061		$	143,490
Interest income		971			297			312
Interest expense, net		(67,389	)		(72,577	)		(84,654	)
Foreign currency translation and transaction losses		(5,534	)		(1,622	)		(5,839	)
Income attributable to sale of equity interest		16,503			25,431			24,143
Gain from sale of property, plant and equipment		—			—			7,628
Other non-operating income, net		(5,345	)		(1,991	)		756
Total consolidated income before income taxes and equity in income of investees	$	141,088		$	113,599		$	85,836

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company sells electricity and products for power plants and others, mainly to the geographical areas according to location of the customers, as detailed below. The following tables present certain data by geographic area:

	Year Ended December 31,
	2016		2015		2014
	(Dollars in thousands)
Revenues from external customers attributable to: (1)
United States	$	307,025	$	286,509	$	293,710
Indonesia		100,856		93,191		38,174
Kenya		109,270		86,545		86,074
Turkey		46,270		57,356		86,340
Chile		58,032		34,478		—
Guatemala		30,086		27,897		28,439
Other foreign countries		11,052		8,668		26,787
Consolidated total	$	662,591	$	594,644	$	559,524

____________

⁽¹⁾Revenues as reported in the geographic area in which they originate.

	Year Ended December 31,
	2016		2015		2014
	(Dollars in thousands)
Long-lived assets (primarily power plants and related assets) located in:
United States	$	1,414,523	$	1,374,465	$	1,369,136
Kenya		327,157		375,257		330,200
Other foreign countries		199,559		107,407		90,735
Consolidated total	$	1,941,239	$	1,857,129	$	1,790,071

The following table presents revenues from major customers:

	Year Ended December 31,
	2016				2015				2014
	Revenues		%		Revenues		%		Revenues		%
	(Dollars in thousands)				(Dollars in thousands)				(Dollars in thousands)
Southern California Edison (1)	$	33,552		5.1	$	56,026		9.4	$	75,803		13.5
Southern California Public Power Authority (1)		67,566		10.2		30,947		5.2		21,799		3.9
Sierra Pacific Power Company and Nevada Power Company (1)(2)		127,226		19.2		115,876		19.5		92,580		16.5
Hyundai (3)		100,856		15.2		93,131		15.7		38,174		6.8
KPLC (1)		109,270		16.5		86,545		14.6		86,074		15.4

________

⁽¹⁾Revenues reported in Electricity segment.

⁽²⁾Subsidiaries of NV Energy, Inc.

⁽³⁾Revenues related to the Sarulla project that are reported in Products segment.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE21 — TRANSACTIONS WITH RELATED ENTITIES

Transactions between the Company and related entities, other than those disclosed elsewhere in these financial are summarized below:

	Year Ended December 31,
	2016		2015		2014
	(Dollars in thousands)
Property rental fee expense paid to the Parent	$	—	$	303	$	1,821
Corporate financial, administrative, executive services, and research and development services provided to the Parent	$	—	$	148	$	148
Services rendered by an indirect shareholder of the Parent	$	—	$	15	$	51

The current asset due from the Parent at December 31, 2015 in the amount of $1,337,000 represented the net obligation resulting from ongoing operations and transactions with the Parent and is payable from available cash flow. Interest was computed on balances greater than 60 days at LIBOR plus 1% (but not less than the change in the Israeli Consumer Price Index plus 4%) compounded quarterly, and was accrued and paid to the Parent annually. The amount of such balance as of December 31, 2015 is $0.

Restructuring with the Parent

On February 5, 2015, the Tel Aviv Stock Exchange (“TASE”) approved the listing of the Company’s common stock on the TASE. On February 10, 2015, the Company's common stock was successfully listed on the TASE. The TASE also confirmed that the Company will be included in the TA-25 Index, which is the TASE flagship index that tracks the share prices of the 25 companies with the highest market capitalization on the exchange. The Company will remain subject to the rules and regulations of the New York Stock Exchange (“NYSE”) and of the U.S. Securities and Exchange Commission (“SEC”). Under the local regime for dual listing, the Company will use the same periodic reports, financial and other relevant disclosure information that The Company submits to the SEC and NYSE.

On February 12, 2015, the Company completed the share exchange transaction with its then-Parent entity, Ormat Industries Ltd. ("OIL") following which, the Company became a noncontrolled public company and its public float increased from approximately 40% to approximately 76% of its total shares outstanding. Under the terms of the share exchange, OIL shareholders received 0.2592 shares in the Company for each share in OIL, or an aggregate of approximately 30.2 million shares, reflecting a net issuance of approximately 3.0 million shares (after deducting the 27.2 million shares that OIL held in the Company). Consequently, the number of total shares of the Company outstanding increased from approximately 45.5 million shares to approximately 48.5 million shares as of the closing of the share exchange.

In exchange, the Company also received $15.4 million in cash, $0.6 million in other assets and $12.1 million in land and buildings and assumed $0.5 million in liabilities. OIL's principal business purpose was to hold its interest in the Company and the transaction resulted in a transfer of non-material assets from OIL to the Company. Therefore, there was no change in the reporting entity as a result of the transaction and the Company recognized the transfer of net assets at their carrying value as presented in OIL's financial statements. Any activities of OIL will be accounted for prospectively by the Company

Corporate and administrative services agreement with the Parent

Ormat Systems and the Parent had agreements whereby Ormat Systems provided to the Parent, for a monthly fee of $10,000 (adjusted annually, in part based on changes in the Israeli Consumer Price Index), certain corporate administrative services, including the services of executive officers. In addition, Ormat Systems agreed to provide the Parent with services of certain skilled engineers and other research and development employees at Ormat Systems’ cost plus 10%.

Lease agreements with the Parent

Ormat Systems had a rental agreement with the Parent entered into in July 2004 for the sublease of office and manufacturing facilities in Yavne, Israel, for a monthly rent of $52,000, adjusted annually for changes in the Israeli Consumer Price Index, plus taxes and other costs to maintain the properties. The term of the rental agreement was for a period ending the earlier of: (i) 25 years from July 1, 2004; or (ii) the remaining periods of the underlying lease agreements between the Parent and the Israel Land Administration (which terminate between 2018 and 2047).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Effective April 1, 2009, Ormat Systems entered into an additional rental agreement with the Parent for the sublease of additional manufacturing facilities adjacent to the current manufacturing facilities in Yavne, Israel. The term of the additional rent agreement was to expire on the same day as the abovementioned lease agreement entered into in July 2004. Pursuant to the additional lease agreement, Ormat Systems paid a monthly rent of $77,000, adjusted annually for changes in the Israeli Consumer Price Index, plus tax and other costs to maintain the properties.

Registration rights agreement

Prior to the closing of the Company’s initial public offering in November 2004, the Company and the Parent entered into a registration rights agreement pursuant to which the Parent may require the Company to register its common stock for sale on Form S-1 or Form S-3. The Company also agreed to pay all expenses that result from the registration of the Company’s common stock under the registration rights agreement, other than underwriting commissions for such shares and taxes. The Company has also agreed to indemnify the parent, its directors, officers and employees against liability that may result from their sale of the Company’s common stock, including Securities Act liabilities.

As of February 12, 2015, the above-mentioned agreements are no longer effective as a result of the restructuring transaction described above.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 22 — EMPLOYEE BENEFIT PLAN

401(k) Plan

The Company has a 401(k) Plan (the “Plan”) for the benefit of its U.S. employees. Employees of the Company and its U.S. subsidiaries who have completed one year of service or who had one year of service upon establishment of the Plan are eligible to participate in the Plan. Contributions are made by employees through pretax deductions up to 60% of their annual salary. In 2016, 2015 and 2014, contributions made by the Company were matched up to a maximum of 3%, 2% and 2% of the employee’s annual salary, respectively. The Company’s contributions to the Plan were $1.0 million, $0.6 million, and $0.5 million for the years ended December 31, 2016, 2015, and 2014, respectively.

Severance plan

The Company, through Ormat Systems, provides limited non-pension benefits to all current employees in Israel who are entitled to benefits in the event of termination or retirement in accordance with the Israeli Government sponsored programs. These plans generally obligate the Company to pay one month’s salary per year of service to employees in the event of involuntary termination. There is no limit on the number of years of service in the calculation of the benefit obligation. The liabilities for these plans are recorded at each balance sheet date by determining the undiscounted obligation as if it were payable at that point in time. Such liabilities have been presented in the consolidated balance sheets as “liabilities for severance pay”. The Company has an obligation to partially fund the liabilities through regular deposits in pension funds and severance pay funds. The amounts funded amounted to $12.8 million and $14.2 million at December 31, 2016 and 2015, respectively, and have been presented in the consolidated balance sheets as part of “deposits and other”. The severance pay liability covered by the pension funds is not reflected in the financial statements as the severance pay risks have been irrevocably transferred to the pension funds. Under the Israeli severance pay law, restricted funds may not be withdrawn or pledged until the respective severance pay obligations have been met. As allowed under the program, earnings from the investment are used to offset severance pay costs. Severance pay expenses for the years ended December 31, 2016, 2015, and 2014 were $2.3 million, $2.5 million, and $2.1 million, respectively, which are net of income (including loss) amounting to $0.3 million, $0.1 million, and $(1.5) million, respectively, generated from the regular deposits and amounts accrued in severance funds.

The Company expects to pay the following future benefits to its employees upon their reaching normal retirement age:

			(Dollars in thousands)
Year ending December 31:
2017			$	1,867
2018				2,497
2019				1,655
2020				1,119
2021				1,400
2022	-	2026		5,141
			$	13,679

The above amounts were determined based on the employees’ current salary rates and the number of years’ service that will have been accumulated at their retirement date. These amounts do not include amounts that might be paid to employees that will cease working with the Company before reaching their normal retirement age.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 23 — COMMITMENTS AND CONTINGENCIES

Geothermal resources

The Company, through its project subsidiaries in the United States, controls certain rights to geothermal fluids through certain leases with the Bureau of Land Management (“BLM”) or through private leases. Royalties on the utilization of the geothermal resources are computed and paid to the lessors as defined in the respective agreements. Royalty expense under the geothermal resource agreements were $17.1 million, $15.4 million, and $16.3 million for the years ended December 31, 2016, 2015, and 2014, respectively.

Letters of credit

In the ordinary course of business with customers, vendors, and lenders, the Company is contingently liable for performance under letters of credit totaling $341.6 million at December 31, 2016. Management does not expect any material losses to result from these letters of credit because performance is not expected to be required, and, therefore, is of the opinion that the fair value of these instruments is zero.

Purchase commitments

The Company purchases raw materials for inventories, construction-in-process and services from a variety of vendors. During the normal course of business, in order to manage manufacturing lead times and help assure adequate supply, the Company enters into agreements with contract manufacturers and suppliers that either allow them to procure goods and services based upon specifications defined by the Company, or that establish parameters defining the Company’s requirements.

At December 31, 2016, total obligations related to such supplier agreements were approximately $108.1 million (out of which approximately $51.0 million relate to construction-in-process). All such obligations are payable in 2017.

Grants and royalties

The Company, through Ormat Systems, had historically, through December 31, 2003, requested and received grants for research and development from the Office of the Chief Scientist of the Israeli Government. Ormat Systems is required to pay royalties to the Israeli Government at a rate of 3.5% to 5.0% of the revenues derived from products and services developed using these grants. No royalties were paid for the years ended December 31, 2016, 2015, and 2014. The Company is not liable for royalties if the Company does not sell such products and services. Such royalties are capped at the amount of the grants received plus interest at LIBOR. The cap at December 31, 2016 and 2015, amounted to $1.8 million and $1.7 million, respectively, of which approximately $0.8 million and $0.8 million, respectively, represents interest based on the LIBOR rate, as defined above.

Lease commitments

At December 31, 2016, 2015 and 2014, total lease expenses for leasing of land, building and equipment outside of the Puna lease (separately described in Note 13) amounted to $0.4 million, $0.4 million and $0.3 million respectively. The related future minimum lease payments are immaterial for each year.

In 2015, the Company entered into a lease transaction for a fleet of vehicles. The lease transaction was classified as a capital lease and the leased vehicles were classified under Property, Plant and Equipment in total amount of $6.9 million, representing vehicles that were received during 2015 and 2016. The terms of the lease are monthly payments in equal installments over 5 years. The related future minimum lease payments are immaterial for each year.

Contingencies

● Jon Olson and Hilary Wilt, together with Puna Pono Alliance filed a complaint on February 17, 2015 in the Third Circuit Court for the State of Hawaii, requesting declaratory and injunctive relief requiring that PGV comply with an ordinance that the plaintiffs allege will prohibit PGV from engaging in night drilling operations at its KS-16 well site. On May 17, 2015, the original complaint was amended to add the county of Hawaii and the State of Hawaii Department of Land and Natural Resources as defendants to the case. On October 10, 2016, the court issued its decision in response to each of the plaintiffs’ and defendants’ motions for summary judgment, denying plaintiffs’ motion and granting defendant PGV's and the County of Hawaii’s cross motions for summary judgment, effectively rendering the plaintiffs’ action moot. On January 17, 2017, the plaintiffs filed a notice of appeal of the October 10, 2016 decision.  Procedural issues as to the ability of the plaintiffs to appeal the decision at this time, including the jurisdiction of the appellate court to near the appeal, are also before the court.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

● On July 8, 2014, Global Community Monitor, LiUNA, and two residents of Bishop, California filed a complaint in the U.S. District Court for the Eastern District of California, alleging that Mammoth Pacific, L.P., the Company and Ormat Nevada are operating three geothermal generating plants in Mammoth Lakes, California (MP-1, MP-II and PLES-I) in violation of the federal Clean Air Act and Great Basin Unified Air Pollution Control District rules. On June 26, 2015, in response to a motion by the defendants, the court dismissed all but one of the plaintiffs’ causes of action. On January 6, 2017, the court issued its order regarding several pending motions, including plaintiffs’ motion for partial summary judgment, defendants' motion for summary judgment, defendants' motion to exclude and defendants' motion for leave to file a sur-reply. The impact of the court’s January 6 order is to deny the plaintiffs’ sole remaining cause of action.

● On April 5, 2012, the International Brotherhood of Electrical Workers Local 1260 (“Union”) filed a petition with the NLRB seeking to organize the operations and maintenance employees at the Puna project.  A global settlement was reached in principle in February 2016, which includes a Union disclaimer of interest, the withdrawal of letters from the Union to the NRLB and signed individual settlement agreements, all of which are immaterial. All issues are now settled and closed.

● In January 2014, Ormat learned that two former employees filed a “qui tam” complaint seeking damages, penalties and other relief of approximately $375 million, alleging that the Company and certain of its subsidiaries (collectively, the “Ormat Parties”) submitted fraudulent applications and certifications to obtain grants for the Puna and North Brawley projects. The U.S. Department of Justice declined to intervene. On October 25, 2016, the parties entered into a final settlement agreement providing for the dismissal of the claim without any admission of wrongdoing by the Ormat Parties and payment of $11 million (inclusive of fees and costs). The settlement amount of $11 million was included in general and administrative expenses in the consolidated statements of operations and comprehensive income for the year ended December 31, 2016. 

● On March 29, 2016, a former local sales representative in Chile, Aquavant, S.A., filed a claim on the basis of unjust enrichment against Ormat’s subsidiaries in the 27th Civil Court of Santiago, Chile. The claim requests that the court order Ormat to pay Aquavant $4.6 million in connection with its activities in Chile, including the EPC contract for the Cerro Pabellon project and various geothermal concessions, plus 3.75% of Ormat geothermal products sales in Chile over the next 10 years. Pursuant to various petitions submitted by defendants, including a motion describing preliminary, procedural defenses, on August 18, 2016, and then on October 10, 2016, the 27th Civil Court issued a number of decisions, which include removal of the case to the 11th Civil Court of Santiago, thereby delaying a determination on the larger issues of jurisdiction and competency of the Chilean courts as a substantive (and not procedural) defense.   The Company believes that it has valid defenses under law, and intends to defend itself vigorously.

●  On August 5, 2016, George Douvris, Stephanie Douvris, Michael Hale, Cheryl Cacocci, Hillary E. Wilt and Christina Bryan, acting for themselves and on behalf of all other similarly situated residents of the lower Puna District, filed a complaint in the Third Circuit Court for the State of Hawaii seeking certification of a class action for preliminary and permanent injunctive relief, consequential and punitive damages, attorney’s fees and statutory interest against PGV and other presently unknown defendants. The complaint purports that injuries and other damages in an undisclosed amount were caused to the plaintiffs as a result of an alleged toxic release by PGV in the wake of Hurricane Iselle in August 2014. On August 25, 2016, the Company filed to remove the case to the U.S. District Court for the District of Hawaii. On December 12, 2016, the District Court granted plaintiffs’ motion for joinder of HELCO as an additional defendant, to amend the complaint, and to remand the case back to the Third Circuit Court. The Company believes that it has valid defenses under law, and intends to defend itself vigorously.

● On May 21, 2014, Elko County, Nevada appealed to the Supreme Court of Nevada the Nevada Governor's Office of Energy’s award of an energy tax abatement to ORNI 42 LLC for our Tuscarora power plant. Lander County, Nevada similarly appealed the Office of Energy’s Award of an energy tax abatement to ORNI 39 LLC for one of our McGinness power plant. Both of the appeals request that the Court overturn the Office of Energy’s decision and deny, retroactively and going forward, the tax abatement benefits for the full 20 year period, valued at approximately $18.6 million for one of our McGinness power plant and approximately $6.2 million for our Tuscarora power plant, of which only a small portion was utilized as of September 30, 2016. Following full briefing on both plaintiffs’ and defendants’ motions for summary judgment, on December 21, 2016, the Supreme Court of Nevada issued its Order of Affirmance of the judgement of the District Court denying the petitions for judicial review of both Lander County and Elko County, and affirming ORNI 39 and ORNI 42's rights to obtain the partial property tax abatements for their respective facilities.

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

●  On June 20, 2016, Nadia Garcia, individually and as successor in interest to Thomas Garcia Valenzuela, and as guardian ad litem to Emerie Garcia, Khamilla Garcia and Reyene Adam, filed a complaint against Ormat Technologies, Ormat Nevada and Ormesa LLC in the Superior Court of Imperial County seeking unspecified monetary damages. The complaint alleges that the Ormat defendants caused the wrongful death, personal injury and other harm to Thomas Garcia when he was employed by Martin Hydroblasting Services, Inc. and suffered injuries leading to his death while performing work at the Ormesa plant site on or around March 31, 2016. Early discovery and conferences are underway. The insurer of the deceased’s employer, and Ormat’s insurer, have accepted tender of this claim and are providing Ormat with a defense in the lawsuit, subject to reservation of rights to deny coverage under the policy and under the law.

In addition, from time to time, the Company is named as a party to various other lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our business. These actions typically seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to such lawsuits, claims and proceedings, the Company accrues reserves when a loss is probable and the amount of such loss can be reasonably estimated. It is the opinion of the Company’s management that the outcome of these proceedings, individually and collectively, will not be material to the Company’s consolidated financial statements as a whole.

202

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 24 — QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	Three Months Ended
	Mar. 31, 2015			June 30, 2015			Sept. 30, 2015			Dec. 31, 2015			Mar. 31, 2016			June 30, 2016			Sept. 30, 2016			Dec. 31, 2016
	(Dollars in thousands, except per share amounts)
Revenues:
Electricity	$	89,953		$	90,926		$	97,245		$	97,796		$	107,868		$	104,001		$	109,795		$	114,628
Product		30,278			49,561			65,607			73,278			43,726			55,860			74,822			51,891
Total revenues		120,231			140,487			162,852			171,074			151,594			159,861			184,617			166,519
Cost of revenues:
Electricity		55,581			62,522			61,501			63,008			63,686			62,243			66,481			69,163
Product		20,625			27,182			42,019			43,927			24,035			31,822			43,647			30,719
Total cost of revenues		76,206			89,704			103,520			106,935			87,721			94,065			110,128			99,882
Gross profit		44,025			50,783			59,332			64,139			63,873			65,796			74,489			66,637
Operating expenses:
Research and development expenses		363			414			335			668			349			595			1,086			732
Selling and marketing expenses		3,433			4,283			4,383			3,978			3,675			3,668			4,793			4,288
General and administrative expenses		10,204			7,443			7,950			9,185			8,749			8,783			19,093			10,085
Write-off of unsuccessful exploration activities		174			--			185			1,220			557			863			1,294			303
Operating income		29,851			38,643			46,479			49,088			50,543			51,887			48,223			51,229
Other income (expense):
Interest income		9			44			53			191			320			245			266			140
Interest expense, net		(17,828	)		(18,859	)		(17,748	)		(18,142	)		(16,023	)		(18,401	)		(17,137	)		(15,828	)
Foreign currency translation and transaction gains (losses)		(1,366	)		(571	)		1,296			(981	)		1,962			(4,332	)		(222	)		(2,942	)
Income attributable to sale of tax benefits		5,552			4,731			8,634			6,514			4,398			4,519			3,463			4,123
Other non-operating income (expense), net		283			(1,675	)		(131	)		(468	)		191			49			(5,546	)		(39	)
Income (loss) from continuing operations, before income taxes and equity in income of investees		16,501			22,313			38,583			36,202			41,391			33,967			29,047			36,683
Income tax benefit (provision)		(5,459	)		(6,056	)		38,211			(11,438	)		(9,509	)		(7,890	)		(11,988	)		(2,450	)
Equity in income (losses) of investees		(775	)		(984	)		(3,133	)		(616	)		(937	)		(1,144	)		(2,653	)		(3,001	)
Net income (loss)		10,267			15,273			73,661			24,148			30,945			24,933			14,406			31,232
Net loss (income) attributable to noncontrolling interest		(235	)		(859	)		(1,522	)		(1,160	)		(1,674	)		(584	)		(2,326	)		(3,002	)
Net income (loss) attributable to the Company's stockholders	$	10,032		$	14,414		$	72,139		$	22,988		$	29,271		$	24,349		$	12,080		$	28,230
Earnings (loss) per share attributable to the Company's stockholders
Basic:
Net income	$	0.21		$	0.29		$	1.47		$	0.47		$	0.60		$	0.49		$	0.24		$	0.57
Diluted:
Net income	$	0.21		$	0.28		$	1.41		$	0.46		$	0.59		$	0.49		$	0.24		$	0.56
Weighted average number of shares used in computation of earnings per share attributable to the Company's stockholders:
Basic		47,244			48,881			49,023			49,074			49,173			49,456			49,599			49,647
Diluted		48,079			50,600			51,113			49,668			49,782			50,137			50,289			50,293

203

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 25 — SUBSEQUENT EVENTS

Cash dividend

On February 28, 2017, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $8.4 million ($0.17 per share) to all holders of the Company’s issued and outstanding shares of common stock on March 15, 2017, payable on March 29, 2017.

204

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

The Company’s management, including its Chief Executive Officer and Chief Financial Officer, have conducted an evaluation of the effectiveness of disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation, the Company’s management, including the Chief Executive Officer and Chief Financial Officer, concluded as of December 31, 2016, that the disclosure controls and procedures were effective in ensuring that all material information required to be filed in reports that the Company files or submits under the Exchange Act has been recorded, processed, summarized and reported when required and the information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined under Rule 13a-15(f) under the Exchange Act. Internal control over financial reporting is a process designed 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.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, 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 and procedures may deteriorate.

Management, under the supervision and participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s internal control over financial reporting as of December 31, 2016 using criteria established in Internal Control — Integrated Framework (2013) issued by the COSO and concluded that the Company maintained effective internal control over financial reporting as of December 31, 2016.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2016 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Changes in Internal Control over Financial Reporting

No changes in the Company’s internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act, have been identified during the Company’s fourth fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

205

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information required by this Item and not set forth below is incorporated herein by reference to the Company’s definitive proxy statement for the 2017 annual meeting .

The following table sets forth the name, age and positions of our directors, executive officers and persons who are executive officers of certain of our subsidiaries who perform policy making functions for us:

Name	Age	Position
Stanley B. Stern	59	Independent Director (1)
Gillon Beck	55	Chairman of the Board of Directors (3)
Dan Falk	72	Independent Director (3)
Ami Boehm	45	Independent Director (2)
Ravit Bar-Niv	53	Independent Director (2)
Robert F. Clarke	74	Independent Director (2)
Robert E. Joyal	72	Independent Director (1)
David Granot	70	Independent Director (1)
Isaac Angel	60	Chief Executive Officer*
Doron Blachar	49	Chief Financial Officer*
Zvi Krieger	61	Executive Vice President—Electricity Segment*
Bob Sullivan	54	Executive Vice President - Business Development Sales & Marketing
Shlomi Argas	52	Executive Vice President - Projects*
Shimon Hatzir	55	Executive Vice President—Engineering*
Erez Klein	51	Executive Vice President - Production*
Nir Wolf	51	Executive Vice President – Market Development*
Etty Rosner	61	Corporate Secretary; Senior Vice President—Contract Management*

*Performs the functions described in the table, but is employed by Ormat Systems

1) Denotes Class I Director – Term expiring at 2017 Annual Shareholders Meeting

2) Denotes Class II Director – Term expiring at 2018 Annual Shareholders Meeting

3) Denotes Class III Director – Term expiring at 2019 Annual Shareholders Meeting

Audit Committee

Information required by this Item and not set forth below is incorporated herein by reference to the Company’s definitive proxy statement for the 2017 annual meeting .

ITEM 11. EXECUTIVE COMPENSATION

Information required by this Item and not set forth below is incorporated herein by reference to the Company’s definitive proxy statement for the 2017 annual meeting .

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required by this Item and not set forth below is incorporated herein by reference to the Company’s definitive proxy statement for the 2017 annual meeting .

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by this Item and not set forth below is incorporated herein by reference to the Company’s definitive proxy statement for the 2017 annual meeting .

206

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required by this Item and not set forth below is incorporated herein by reference to the Company’s definitive proxy statement for the 2017 annual meeting .

207

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) (1) List of Financial Statements

See Index to Financial Statements in Part II, Item 8 of this annual report.

     (2) List of Financial Statement Schedules

All applicable schedule information is included in our Financial Statements in Part II, Item 8 of this annual report.

(b) Exhibit Index. We hereby file, as exhibits to this Annual Report, those exhibits listed on the Exhibit Index immediately following the signature page hereto.

208

SIGNATURES

Pursuant to the requirements of Section 13 or 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.

ORMAT TECHNOLOGIES, INC.
By:	/s/ Isaac Angel
	Name:  Isaac Angel
	Title:    Chief Executive Officer

Date: March 1, 2017

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 indicated, on March 1, 2017.

Signature	Capacity
/s/     Isaac Angel	Chief Executive Officer
Isaac Angel	(Principal Executive Officer)
/s/ DORON BLACHAR	Chief Financial Officer
Doron Blachar	(Principal Financial and Accounting Officer)
/s/ GILLON BECK	Chairman of the Board of Directors
Gillon Beck
/s/    AMI BOEHM	Director
Ami Boehm
/s/    DAN FALK	Director
Dan Falk
/s/    DAVID GRANOT	Director
David Granot
/s/    RAVIT BAR NIV	Director
Ravit Bar Niv
/s/    ROBERT E. JOYAL	Director
Robert E. Joyal
/s/    ROBERT F. CLARKE	Director
Robert F. Clarke
/s/    STANLEY B. STERN	Director
Stanley B. Stern

209

(C) EXHIBIT INDEX

Exhibit

NO.

No.	Document
3.1	Second Amended and Restated Certificate of Incorporation, incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

3.2 Third Amended and Restated By-laws, incorporated by reference to Exhibit 3.2 to Ormat Technologies, Inc. Current Report on Form 8-K filed with the Securities and Exchange Commission on February 26, 2009.

3.3 Amended and Restated Limited Liability Company Agreement of OPC LLC dated June 7, 2007, by and among Ormat Nevada Inc., Morgan Stanley Geothermal LLC, and Lehman-OPC LLC, incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on June 13, 2007.

3.4 Amended and Restated Limited Liability Company Agreement of ORPD LLC, dated April 30, 2015, by and among Ormat Nevada Inc., Northleaf Geothermal Holdings LLC, and ORPD Holding LLC incorporated by reference to Exhibit 3.4 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on May 6, 2015.

4.1 Form of Common Share Stock Certificate, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

4.2 Form of Preferred Share Stock Certificate, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

4.3 Form of Rights Agreement by and between Ormat Technologies, Inc. and American Stock Transfer & Trust Company, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.

4.4 Indenture for Senior Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.

4.5 Indenture for Subordinated Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.

4.6 Deed of Trust, dated as of August 3, 2010, between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 2, 2011.

4.7 Addendum, dated as of January 27, 2011, to the Deed of Trust, dated as of August 3, 2010, between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 2, 2011.

4.8 Form of Bond issued pursuant to the Deed of Trust, dated as of August 3, 2010 (as amended or supplemented), between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 2, 2011.

4.9 Second Addendum, dated as of February 11, 2011, to the Deed of Trust, dated as of August 3, 2010 (as amended or supplemented), between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., incorporated by reference to Exhibit 4.7 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on May 6, 2011.

4.10 Indenture of Trust and Security Agreement, dated September 23, 2011, among OFC 2 LLC, ORNI 15 LLC, ORNI 39 LLC, ORNI 42 LLC, HSS II, LLC, and Wilmington Trust Company, as Trustee and Depository, incorporated by reference to Exhibit 4.8 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on November 4, 2011.

4.11 Third Addendum, dated as of December 1, 2011, to a Deed of Trust, dated as of August 3, 2010 as amended on January 31, 2011 (effective as of January 27, 2011) and on February 13, 2011, between Ormat Technologies, Inc. and Mishmeret — Trusts Services Company Ltd. (formerly Ziv Haft Trust Company Ltd.), as trustee, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on December 1, 2011.

10.1.1 Indenture, dated February 13, 2004, among Ormat Funding Corp., Brady Power Partners, Steamboat Development Corp., Steamboat Geothermal LLC, OrMammoth Inc., ORNI 1 LLC, ORNI 2 LLC, ORNI 7 LLC, Ormesa LLC and Union Bank of California, incorporated by reference to Exhibit 10.1.7 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.1.2 First Supplemental Indenture, dated May 14, 2004, among Ormat Funding Corp., Brady Power Partners, Steamboat Development Corp., Steamboat Geothermal LLC, OrMammoth Inc., ORNI 1 LLC, ORNI 2 LLC, ORNI 7 LLC, Ormesa LLC and Union Bank of California, incorporated by reference to Exhibit 10.1.8 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

210

Exhibit No. Document

10.1.3 Fifth Supplemental Indenture, dated April 26, 2006, among Ormat Funding Corp. and Union Bank of California, N.A., incorporated by reference to Exhibit 10.1.6 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q (File No 001-32347) to the Securities and Exchange Commission on August 7, 2006.

10.1.4 Loan Agreement, dated October 1, 2003, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.9 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.1.5 Amendment No. 1 to Loan Agreement, dated September 20, 2004, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.10 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.1.6 Guarantee Fee Agreement, dated January 1, 1999, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.13 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.1.7 Reimbursement Agreement, dated July 15, 2004, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.14 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.1.8 Services Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd., incorporated by reference to Exhibit 10.1.15 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.1.9 Agreement for Purchase of Membership Interests in OPC LLC dated June 7, 2007, by and among Ormat Nevada Inc., Morgan Stanley Geothermal LLC and Lehman-OPC LLC, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on June 13, 2007.

10.1.10 First Amendment to Agreement for Purchase of Membership Interests in OPC LLC, dated as of April 17, 2008, by and among Ormat Nevada Inc., Morgan Stanley Geothermal LLC, and Lehman-OPC LLC, incorporated by reference to Exhibit 10.1.18 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on May 7, 2008.

10.1.11 Membership Interest Purchase Agreement, dated as of October 30, 2009, by and among Lehman-OPC LLC, Ormat Nevada Inc. and OPC LLC, incorporated by reference to Exhibit 10.1.13 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on November 3, 2009.

10.1.12 Agreement for Purchase of Membership Interests in ORPD LLC, dated as of February 5, 2015, by and between Ormat Nevada Inc. and Northleaf Geothermal Holdings LLC is incorporated by reference to Exhibit 3.4 to Ormat Technologies, Inc.'s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 6, 2015.

10.1.13 Agreement for Purchase of Membership Interests in ORNI 37 LLC, dated as of November 22, 2016, by and between Northleaf Geothermal Holdings LLC and Ormat Nevada Inc., filed herewith.

10.1.14 Amended and Restated Limited Liability Company Agreement of Opal Geo LLC, dated as of December 16, 2016, by and between OrLeaf LLC and JPM Capital Corporation, filed herewith.

10.1.15 Equity Contribution Agreement, dated as of December 16, 2016, by and among JPM Capital Corporation, Ormat Nevada Inc. and OrLeaf LLC, filed herewith.

10.2.1 Power Purchase Contract, dated July 18, 1984, between Southern California Edison Company and Republic Geothermal, Inc., incorporated by reference to Exhibit 10.3.1 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.2 Amendment No. 1, to the Power Purchase Contract, dated December 23, 1988, between Southern California Edison Company and Ormesa Geothermal, incorporated by reference to Exhibit 10.3.2 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

211

Exhibit No. Document

10.2.3 Power Purchase Contract, dated June 13, 1984, between Southern California Edison Company and Ormat Systems, Inc., incorporated by reference to Exhibit 10.3.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.4 Power Purchase and Sales Agreement, dated as of August 26, 1983, between Chevron U.S.A. Inc. and Southern California Edison Company, incorporated by reference to Exhibit 10.3.4 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.2.5 Amendment No. 1, to Power Purchase and Sale Agreement, dated as of December 11, 1984, between Chevron U.S.A. Inc., HGC and Southern California Edison Company, incorporated by reference to Exhibit 10.3.5 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004

10.2.6 Settlement Agreement and Amendment No. 2, to Power Purchase Contract, dated August 7, 1995, between HGC and Southern California Edison Company, incorporated by reference to Exhibit 10.3.6 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.7 Power Purchase Contract dated, April 16, 1985, between Southern California Edison Company and Second Imperial Geothermal Company, incorporated by reference to Exhibit 10.3.7 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.8 Amendment No. 1, dated as of October 23, 1987, between Southern California Edison Company and Second Imperial Geothermal Company, incorporated by reference to Exhibit 10.3.8 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.2.9 Amendment No. 2, dated as of July 27, 1990, between Southern California Edison Company and Second Imperial Geothermal Company, incorporated by reference to Exhibit 10.3.9 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.2.10 Amendment No. 3, dated as of November 24, 1992, between Southern California Edison Company and Second Imperial Geothermal Company, incorporated by reference to Exhibit 10.3.10 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.2.11 Amended and Restated Power Purchase and Sales Agreement, dated December 2, 1986, between Mammoth Pacific and Southern California Edison Company, incorporated by reference to Exhibit10.3.11 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.12 Amendment No. 1, to Amended and Restated Power Purchase and Sale Agreement, dated May 18, 1990, between Mammoth Pacific and Southern California Edison Company, incorporated by reference to Exhibit 10.3.12 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.2.13 Power Purchase Contract, dated April 15, 1985, between Mammoth Pacific and Southern California Edison Company, incorporated by reference to Exhibit 10.3.13 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.14 Amendment No. 1, dated as of October 27, 1989, between Mammoth Pacific and Southern California Edison Company, incorporated by reference to Exhibit 10.3.14 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.15 Amendment No. 2, dated as of December 20, 1989, between Mammoth Pacific and Southern California Edison Company, incorporated by reference to Exhibit 10.3.15 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.2.16 Power Purchase Contract, dated April 16, 1985, between Southern California Edison Company and Santa Fe Geothermal, Inc., incorporated by reference to Exhibit 10.3.16 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.17 Amendment No. 1, to Power Purchase Contract, dated October 25, 1985, between Southern California Edison Company and Mammoth Pacific, incorporated by reference to Exhibit 10.3.17 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.18 Amendment No. 2, to Power Purchase Contract, dated December 20, 1989, between Southern California Edison Company and Pacific Lighting Energy Systems, incorporated by reference to Exhibit 10.3.18 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

212

Exhibit No. Document

10.2.19 Interconnection Facilities Agreement, dated October 20, 1989, by and between Southern California Edison Company and Mammoth Pacific, incorporated by reference to Exhibit 10.3.19 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.20 Interconnection Facilities Agreement, dated October 13, 1985, by and between Southern California Edison Company and Mammoth Pacific (II), incorporated by reference to Exhibit 10.3.20 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.21 Interconnection Facilities Agreement, dated October 20, 1989, by and between Southern California Edison Company and Pacific Lighting Energy Systems, incorporated by reference to Exhibit 10.3.21 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.22 Interconnection Agreement, dated August 12, 1985, by and between Southern California Edison Company and Heber Geothermal Company incorporated by reference to Exhibit 10.3.22 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.23 Plant Connection Agreement for the Heber Geothermal Plant No. 1, dated, July 31, 1985, by and between Imperial Irrigation District and Heber Geothermal Company incorporated by reference to Exhibit 10.3.23 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.24 Plant Connection Agreement for the Second Imperial Geothermal Company Power Plant No. 1, dated, October 27, 1992, by and between Imperial Irrigation District and Second Imperial Geothermal Company incorporated by reference to Exhibit 10.3.24 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.25 IID-SIGC Transmission Service Agreement for Alternative Resources, dated, October 27, 1992, by and between Imperial Irrigation District and Second Imperial Geothermal Company incorporated by reference to Exhibit 10.3.25 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.2.26 Plant Connection Agreement for the Ormesa Geothermal Plant, dated October 1, 1985, by and between Imperial Irrigation District and Ormesa Geothermal incorporated by reference to Exhibit 10.3.26 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.27 Plant Connection Agreement for the Ormesa IE Geothermal Plant, dated, October 21, 1988, by and between Imperial Irrigation District and Ormesa IE incorporated by reference to Exhibit 10.3.27 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.28 Plant Connection Agreement for the Ormesa IH Geothermal Plant, dated, October 3, 1989, by and between Imperial Irrigation District and Ormesa IH incorporated by reference to Exhibit 10.3.28 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.29 Plant Connection Agreement for the Geo East Mesa Limited Partnership Unit No. 2, dated, March 21, 1989, by and between Imperial Irrigation District and Geo East Mesa Limited Partnership incorporated by reference to Exhibit 10.3.29 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.30 Plant Connection Agreement for the Geo East Mesa Limited Partnership Unit No. 3, dated, March 21, 1989, by and between Imperial Irrigation District and Geo East Mesa Limited Partnership incorporated by reference to Exhibit 10.3.30 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.31 Transmission Service Agreement for the Ormesa I, Ormesa IE and Ormesa IH Geothermal Power Plants, dated, October 3, 1989, between Imperial Irrigation District and Ormesa Geothermal incorporated by reference to Exhibit 10.3.31 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.32 Transmission Service Agreement for the Geo East Mesa Limited Partnership Unit No. 2, dated, March 21, 1989, by and between Imperial Irrigation District and Geo East Mesa Limited Partnership incorporated by reference to Exhibit 10.3.32 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

213

Exhibit No. Document

10.2.33 Transmission Service Agreement for the Geo East Mesa Limited Partnership Unit No. 3, dated, March 21, 1989, by and between Imperial Irrigation District and Geo East Mesa Limited Partnership incorporated by reference to Exhibit 10.3.33 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.34 IID-Edison Transmission Service Agreement for Alternative Resources, dated, September 26, 1985, by and between Imperial Irrigation District and Southern California Edison Company incorporated by reference to Exhibit 10.3.34 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.35 Plant Amendment No. 1, to IID-Edison Transmission Service Agreement for Alternative Resources, dated, August 25, 1987, by and between Imperial Irrigation District and Southern California Edison Company incorporated by reference to Exhibit 10.3.35 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.36 Agreement Addressing Renewable Energy Pricing and Payment Issues, dated June 15, 2001, by and between Second Imperial Geothermal Company QFID No. 3021 and Southern California Edison Company incorporated by reference to Exhibit 10.3.39 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.37 Amendment No. 1 to Agreement Addressing Renewable Energy Pricing and Payment Issues, dated November 30, 2001, by and between Second Imperial Geothermal Company QFID No. 3021 and Southern California Edison Company incorporated by reference to Exhibit 10.3.40 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.38 Agreement Addressing Renewable Energy Pricing and Payment Issues, dated June 15, 2001, by and between Heber Geothermal Company QFID No. 3001 and Southern California Edison Company incorporated by reference to Exhibit 10.3.41 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.39 Amendment No. 1 to Agreement Addressing Renewable Energy Pricing and Payment Issues, dated November 30, 2001, by and between Heber Geothermal Company QFID No. 3001 and Southern California Edison Company incorporated by reference to Exhibit 10.3.42 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.40 Energy Services Agreement, dated February 2003, by and between Imperial Irrigation District and ORMESA, LLC incorporated by reference to Exhibit 10.3.43 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.41 Purchase Power Contract, dated March 24, 1986, by and between Hawaii Electric Light Company and Thermal Power Company incorporated by reference to Exhibit 10.3.44 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.42 Firm Capacity Amendment to Purchase Power Contract, dated July 28, 1989, by and between Hawaii Electric Light Company and Puma Geothermal Venture incorporated by reference to Exhibit 10.3.45 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.43 Amendment to Purchase Power Contract, dated October 19, 1993, by and between Hawaii Electric Light Company and Puma Geothermal Venture incorporated by reference to Exhibit 10.3.46 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.44 Third Amendment to the Purchase Power Contract, dated March 7, 1995, by and between Hawaii Electric Light Company and Puna Geothermal Venture incorporated by reference to Exhibit 10.3.47 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.45 Performance Agreement and Fourth Amendment to the Purchase Power Contract, dated February 12, 1996, by and between Hawaii Electric Light Company and Puna Geothermal Venture incorporated by reference to Exhibit 10.3.48 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.2.46 Agreement to Design 69 KV Transmission Lines, a Substation at Pohoiki, Modifications to Substations at Puna and Kaumana, and a Temporary 34.5 Facility to Interconnect PGV’s Geothermal Electric Plant with HELCO’s System Grid (Phase II and III), dated June 7, 1990, by and between Hawaii Electric Light Company and Puna Geothermal Venture incorporated by reference to Exhibit 10.3.49 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

214

Exhibit No. Document

10.3.1 Ormesa BLM Geothermal Resources Lease CA 966 incorporated by reference to Exhibit 10.4.1 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.2 Ormesa BLM License for Electric Power Plant Site CA 24678 incorporated by reference to Exhibit 10.4.2 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.3 Geothermal Resources Mining Lease, dated February 20, 1981, by and between the State of Hawaii, as Lessor, and Kapoho Land Partnership, as Lessee incorporated by reference to Exhibit 10.4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.4 Geothermal Lease Agreement, dated October 20, 1975, by and between Ruth Walker Cox and Betty M. Smith, as Lessor, and Gulf Oil Corporation, as Lessee incorporated by reference to Exhibit 10.4.4 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.5 Geothermal Lease Agreement, dated August 1, 1976, by and between Southern Pacific Land Company, as Lessor, and Phillips Petroleum Company, as Lessee incorporated by reference to Exhibit 10.4.5 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.6 Geothermal Resources Lease, dated November 18, 1983, by and between Sierra Pacific Power Company, as Lessor, and Geothermal Development Associates, as Lessee incorporated by reference to Exhibit 10.4.6 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.7 Lease Agreement, dated November 1, 1969, by and between Chrisman B. Jackson and Sharon Jackson, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.7 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.3.8 Lease Agreement, dated September 22, 1976, by and between El Toro Land & Cattle Co., as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.8 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.3.9 Lease Agreement, dated February 17, 1977, by and between Joseph L. Holtz, as Lessor, and Chevron U.S.A. Inc., as Lessee incorporated by reference to Exhibit 10.4.9 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.3.10 Lease Agreement, dated March 11, 1964, by and between John D. Jackson and Frances Jones Jackson, also known as Frances J. Jackson, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.10 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.3.11 Lease Agreement, dated February 16, 1964, by and between John D. Jackson, conservator for the estate of Aphia Jackson Wallan, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.11 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.3.12 Lease Agreement, dated March 17, 1964, by and between Helen S. Fugate, a widow, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.12 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.13 Lease Agreement, dated February 16, 1964, by and between John D. Jackson and Frances J. Jackson, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.13 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.14 Lease Agreement, dated February 20, 1964, by and between John A. Straub and Edith D. Straub, also known as John A. Straub and Edythe D. Straub, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.14 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.3.15 Lease Agreement, dated July 1, 1971, by and between Marie L. Gisler and Harry R. Gisler, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.15 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.3.16 Lease Agreement, dated February 28, 1964, by and between Gus Kurupas and Guadalupe Kurupas, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.16 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

215

Exhibit No. Document

10.3.17 Lease Agreement, dated April 7, 1972, by and between Nowlin Partnership, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.17 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.3.18 Geothermal Lease Agreement, dated July 18, 1979, by and between Charles K. Corfman, an unmarried man as his sole and separate property, and Lessor, and Union Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.18 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.19 Lease Agreement, dated January 1, 1972, by and between Holly Oberly Thomson, also known as Holly F. Oberly Thomson, also known as Holly Felicia Thomson, as Lessor, and Union Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.19 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.20 Lease Agreement, dated June 14, 1971, by and between Fitzhugh Lee Brewer, Jr., a married man as his separate property, Donna Hawk, a married woman as her separate property, and Ted Draper and Helen Draper, husband and wife, as Lessor, and Union Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.20 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.21 Lease Agreement, dated May 13, 1971, by and between Mathew J. La Brucherie and Jane E. La Brucherie, husband and wife, and Robert T. O’Dell and Phyllis M. O’Dell, husband and wife, as Lessor, and Union Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.21 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.3.22 Lease Agreement, dated June 2, 1971, by and between Dorothy Gisler, a widow, Joan C. Hill, and Jean C. Browning, as Lessor, and Union Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.22 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.23 Geothermal Lease Agreement, dated February 15, 1977, by and between Walter J. Holtz, as Lessor, and Magma Energy Inc., as Lessee incorporated by reference to Exhibit 10.4.23 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.24 Geothermal Lease, dated August 31, 1983, by and between Magma Energy Inc., as Lessor, and Holt Geothermal Company, as Lessee incorporated by reference to Exhibit 10.4.24 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.25 Unprotected Lease Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd. incorporated by reference to Exhibit 10.4.25 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

10.3.26 Geothermal Resources Lease, dated June 27, 1988, by and between Bernice Guisti, Judith Harvey and Karen Thompson, Trustees and Beneficiaries of the Guisti Trust, as Lessor, and Far West Capital, Inc., as Lessee incorporated by reference to Exhibit 10.4.26 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.27 Amendment to Geothermal Resources Lease, dated January, 1992, by and between Bernice Guisti, Judith Harvey and Karen Thompson, Trustees and Beneficiaries of the Guisti Trust, as Lessor, and Far West Capital, Inc., as Lessee incorporated by reference to Exhibit 10.4.27 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.28 Second Amendment to Geothermal Resources Lease, dated June 25, 1993, by and between Bernice Guisti, Judith Harvey and Karen Thompson, Trustees and Beneficiaries of the Guisti Trust, as Lessor, and Far West Capital, Inc. and its Assignee, Steamboat Development Corp., as Lessee incorporated by reference to Exhibit 10.4.28 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.29 Geothermal Resources Sublease, dated May 31, 1991, by and between Fleetwood Corporation, as Lessor, and Far West Capital, Inc., as Lessee incorporated by reference to Exhibit 10.4.29 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

216

Exhibit No. Document

10.3.30 KLP Lease and Agreement, dated March 1, 1981, by and between Kapoho Land Partnership, as Lessor, and Thermal Power Company, as Lessee incorporated by reference to Exhibit 10.4.30 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.31 Amendment to KLP Lease and Agreement, dated July 9, 1990, by and between Kapoho Land Partnership, as Lessor, and Puna Geothermal Venture, as Lessee incorporated by reference to Exhibit 10.4.31 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.32 Second Amendment to KLP Lease and Agreement, dated December 31, 1996, by and between Kapoho Land Partnership, as Lessor, and Puna Geothermal Venture, as Lessee incorporated by reference to Exhibit 10.4.32 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.3.33 Participation Agreement, dated May 18, 2005, by and among Puna Geothermal Venture, SE Puna, L.L.C., Wilmington Trust Company, S.E. Puna Lease, L.L.C., AIG Annuity Insurance Company, American General Life Insurance Company, Allstate Life Insurance Company and Union Bank of California, incorporated by reference to Exhibit 10.4.33 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q/A to the Securities and Exchange Commission on December 22, 2005.

10.3.34 Project Lease Agreement, dated May 18, 2005, by and between SE Puna, L.L.C. and Puna Geothermal Venture, incorporated by reference to Exhibit 10.4.34 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q/A to the Securities and Exchange Commission on December 22, 2005.

10.4.1 Patent License Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd. incorporated by reference to Exhibit 10.5.4 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.4.2 Form of Registration Rights Agreement by and between Ormat Technologies, Inc. and Ormat Industries Ltd. incorporated by reference to Exhibit 10.5.5 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.

10.5.1 Ormat Technologies, Inc. 2004 Incentive Compensation Plan incorporated by reference to Exhibit 10.6.1 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.

10.5.2 Form of Incentive Stock Option Agreement incorporated by reference to Exhibit 10.6.2 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.

10.5.3 Form of Nonqualified Stock Option Agreement incorporated by reference to Exhibit 10.6.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.

10.6.1 Waiver executed by Lucien Bronicki in favor of Ormat Technologies, Inc., dated May 22, 2012, incorporated by reference to Exhibit 10.6.3 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 11, 2013.

10.6.2 Undertaking executed by Lucien Bronicki in favor of Ormat Industries Ltd. and Ormat Technologies, Inc., dated May 22, 2012, incorporated by reference to Exhibit 10.6.4 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 11, 2013.

10.7.1 Waiver executed by Yehudit Bronicki in favor of Ormat Technologies, Inc., dated May 22, 2012, incorporated by reference to Exhibit 10.7.4 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 11, 2013.

10.7.2 Undertaking executed by Yehudit Bronicki in favor of Ormat Industries Ltd. and Ormat Technologies, Inc., dated May 22, 2012, incorporated by reference to Exhibit 10.7.5 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 11, 2013.

10.8.1 Form of Executive Employment Agreement of Yoram Bronicki incorporated by reference to Exhibit 10.9 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

10.8.2 Amendment to Employment Agreement of Yoram Bronicki, dated March 28, 2008, by and between Ormat Technologies, Inc. and Yoram Bronicki, incorporated by reference to Exhibit 10.8.1 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on May 7, 2008.

217

Exhibit No. Document

10.8.3 Amendment to Employment Agreement of Yoram Bronicki, dated November 4, 2009, by and between Ormat Technologies, Inc. and Yoram Bronicki, incorporated by reference to Exhibit 10.8.3 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on November 9, 2009.

10.8.4 Waiver executed by Yoram Bronicki in favor of Ormat Technologies, Inc., dated May 22, 2012, incorporated by reference to Exhibit 10.8.4 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 11, 2013.

10.8.5 Undertaking executed by Yoram Bronicki in favor of Ormat Industries Ltd. and Ormat Technologies, Inc., dated May 22, 2012, incorporated by reference to Exhibit 10.8.5 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 11, 2013.

10.8.6 Amendment to Employment Agreement of Yoram Bronicki, dated December 10, 2013, by and between Ormat Technologies, Inc. and Yoram Bronicki, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on December 10, 2013.

10.9 Form of Indemnification Agreement incorporated by reference to Exhibit 10.11 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 20, 2004.

10.10 Note Purchase Agreement, dated December 2, 2005, among Lehman Brothers Inc., OrCal Geothermal Inc., OrHeber 1 Inc., OrHeber 2 Inc., Second Imperial Geothermal Company, Heber Field Company and Heber Geothermal Company, incorporated by reference to Exhibit 10.12 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 28, 2006.

10.11.1 Indenture dated as of December 8, 2005 among OrCal Geothermal Inc., OrHeber 1 Inc., OrHeber 2 Inc., Second Imperial Geothermal Company, Heber Field Company and Heber Geothermal Company and Union Bank of California, incorporated by reference to Exhibit 10.13 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 28, 2006.

10.11.2 First Supplemental Indenture dated as of June 14, 2006 amending the Indenture dated as of December 8, 2005 among OrCal Geothermal Inc., OrHeber 1 Inc., OrHeber 2 Inc., Second Imperial Geothermal Company, Heber Field Company and Heber Geothermal Company and Union Bank of California, incorporated by reference to Exhibit 10.13.2 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q (File No 001-32347) to the Securities and Exchange Commission on August 7, 2006.

10.12 Guarantee dated as of December 8, 2005 among OrCal Geothermal Inc., OrHeber 1 Inc., OrHeber 2 Inc., Second Imperial Geothermal Company, Heber Field Company and Heber Geothermal Company, incorporated by reference to Exhibit 10.14 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 28, 2006.

10.13 Note Purchase Agreement, dated February 6, 2004, among Lehman Brothers Inc., Ormat Funding Corp., Brady Power Partners, Steamboat Geothermal LLC, OrMammoth Inc., ORNI 1 LLC, ORNI 2 LLC and ORNI 7 LLC, incorporated by reference to Exhibit 10.15 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 28, 2006.

10.14 Agreement No. 2 Addressing Renewable Energy Pricing Issues, dated May 10, 2006, between Ormesa LLC and Southern California Edison Company, incorporated by reference to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on May 16, 2006.

10.15 Agreement No. 2 Addressing Renewable Energy Pricing Issues, dated May 10, 2006, between Ormesa LLC and Southern California Edison Company, incorporated by reference to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on May 16, 2006.

10.16 Agreement No. 2 Addressing Renewable Energy Pricing Issues, dated May 10, 2006, between Heber Geothermal Company and Southern California Edison Company, incorporated by reference to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on May 16, 2006.

10.17 Agreement No. 2 Addressing Renewable Energy Pricing Issues, dated May 10, 2006, between Second Imperial Geothermal Company and Southern California Edison Company, incorporated by reference to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on May 16, 2006.

10.18.1 Amended and Restated Power Purchase Agreement for Olkaria III Geothermal Plant, dated January 19, 2007, between OrPower 4 Inc. and The Kenya Power and Lighting Company Limited, incorporated by reference to Ormat Technologies, Inc. Annual Report o Form 10-K to the Securities and Exchange Commission on March 12, 2007.

10.18.2 Olkaria III Project Security Agreement, dated January 19, 2007, between OrPower 4 Inc. and The Kenya Power and Lighting Company Limited, incorporated by reference to Ormat Technologies, Inc. Annual Report o Form 10-K to the Securities and Exchange Commission on March 12, 2007.

218

Exhibit No. Document

10.18.3 Common Terms Agreement, dated January 5, 2009, between OrPower 4, Inc. and DEG — Deutsche Investitions-Und Enticklungsgesellschaft MBH, Societe de Promotion et de Participation pour la Cooperation Economique, and BNY Corporate Trustee Services Limited, incorporated by reference to Exhibit 10.18.3 to Ormat Technologies, Inc. Annual Report on Form 10-K for the year ended December 31, 2008 to the Securities and Exchange Commission on March 2, 2009.

10.18.4 DEG A Facility Loan Agreement, dated January 5, 2009, between OrPower 4, Inc. and DEG — Deutsche Investitions-Und Enticklungsgesellschaft MBH and Societe de Promotion et de Participation pour la Cooperation Economique, incorporated by reference to Exhibit 10.18.4 to Ormat Technologies, Inc. Annual Report on Form 10-K for the year ended December 31, 2008 to the Securities and Exchange Commission on March 2, 2009.

10.18.5 DEG B Facility Loan Agreement, dated January 5, 2009, between OrPower 4, Inc. and DEG — Deutsche Investitions-Und Enticklungsgesellschaft MBH and Societe de Promotion et de Participation pour la Cooperation Economique, incorporated by reference to Exhibit 10.18.5 to Ormat Technologies, Inc. Annual Report on Form 10-K for the year ended December 31, 2008 to the Securities and Exchange Commission on March 2, 2009.

10.18.6 DEG C Facility Loan Agreement, dated January 5, 2009, between OrPower 4, Inc. and DEG — Deutsche Investitions-Und Enticklungsgesellschaft MBH and Societe de Promotion et de Participation pour la Cooperation Economique, incorporated by reference to Exhibit 10.18.6 to Ormat Technologies, Inc. Annual Report on Form 10-K for the year ended December 31, 2008 to the Securities and Exchange Commission on March 2, 2009.

10.18.7 Proparco A Facility Loan Agreement, dated January 5, 2009, between OrPower 4, Inc. and DEG — Deutsche Investitions-Und Enticklungsgesellschaft MBH and Societe de Promotion et de Participation pour la Cooperation Economique, incorporated by reference to Exhibit 10.18.7 to Ormat Technologies, Inc. Annual Report on Form 10-K for the year ended December 31, 2008 to the Securities and Exchange Commission on March 2, 2009.

10.19 Amendment No. 2 to the Power Purchase Contract between Ormesa LLC and Ormat Technologies, Inc., and Southern California Edison Company (RAP ID 3012) dated April 23, 2006, incorporated by reference to Exhibit 10.21.2 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on August 8, 2007.

10.20 Joint Ownership Agreement for the Carson Lake Project, dated as of March 12, 2008, by and between Nevada Power Company and ORNI 16 LLC, incorporated by reference to Exhibit 10.24 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on May 7, 2008.

10.21 Note Purchase Agreement, dated as of May 18, 2009, among Ortitlan, Limitada and TCW Global Project Fund II, Ltd., incorporated by reference to Exhibit 10.23 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on May 21, 2009.

10.22 Sale and Purchase Agreement dated August 2, 2010, between ORNI 44 LLC and CD Mammoth Lakes I, Inc. and CD Mammoth Lakes II, Inc., incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on November 4, 2010.

10.23 Note Purchase Agreement, dated September 23, 2011, among OFC 2 LLC, ORNI 15 LLC, ORNI 39 LLC, ORNI 42 LLC, and HSS II, LLC, as Issuers, OFC 2 Noteholder Trust, as Purchaser, John Hancock Life Insurance Company (U.S.A.), as Administrative Agent, and the United States Department of Energy (DOE), as Guarantor, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on November 4, 2011.

10.24.1 Credit Agreement, dated as of November 21, 2011, between Lightning Dock Geothermal HI-01, LLC, and Ormat Nevada Inc., incorporated by reference to Exhibit 10.24.1 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.24.2 Subordination Agreement, dated as of January 11, 2012, among CYRQ ENERGY, Inc., Lightning Dock Geothermal HI-01, LLC, and Ormat Nevada Inc., incorporated by reference to Exhibit 10.24.2 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.24.3 Accounts Agreement, dated as of January 25, 2012, among Lightning Dock Geothermal HI-01, LLC, Ormat Nevada Inc., and Wells Fargo Bank, National Association, as Depositary, incorporated by reference to Exhibit 10.24.3 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.25.1 Credit Agreement, dated December 19, 2011, between Thermo NO. 1 BE-01, LLC, and Ormat Nevada Inc., incorporated by reference to Exhibit 10.25.1 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.25.2 Subordination Agreement, dated as of January 11, 2012, among CYRQ ENERGY, INC., Thermo NO. 1 BE-01, LLC, and Ormat Nevada Inc., incorporated by reference to Exhibit 10.25.2 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

219

Exhibit No. Document

10.25.3 Accounts Agreement, dated as of January 25, 2012 among Thermo NO. 1 BE-01, LLC, Ormat Nevada Inc., and Wells Fargo Bank, National Association, as Depositary, incorporated by reference to Exhibit 10.25.3 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.25.4 Subordination Agreement, dated as of January 11, 2012, among CYRQ ENERGY, INC., Thermo NO. 1 BE-01, LLC, and Ormat Nevada Inc., incorporated by reference to Exhibit 10.25.4 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 11, 2013.

10.25.5 Accounts Agreement, dated as of January 25, 2012 among Thermo NO. 1 BE-01, LLC, Ormat Nevada Inc., and Wells Fargo Bank, National Association, as Depositary, incorporated by reference to Exhibit 10.25.5 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 11, 2013.

10.26.1 Finance Agreement, dated as of August 23, 2012, between OrPower 4, Inc., an indirect wholly-owned subsidiary of Ormat Technologies, Inc., and Overseas Private Investment Corporation, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on November 8, 2012.

10.26.2 Amendment No. 1 to the Finance Agreement, dated as of August 23, 2012, between OrPower 4, Inc., an indirect wholly-owned subsidiary of Ormat Technologies, Inc., and Overseas Private Investment Corporation, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on November 9, 2012.

10.27 Amendment Agreement relating to a Common Terms Agreement, dated October 31, 2012, between OrPower 4, Inc., an indirect wholly-owned subsidiary of Ormat Technologies, Inc., and Deutsche Investitions-und Entwicklungsgesellschaft mbH, incorporated by reference to Exhibit 10.2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on November 9, 2012.

10.28 Equity Contribution Agreement with respect to ORTP, dated as of January 24, 2013,  between Ormat Nevada, Inc., a wholly-owned subsidiary of Ormat Technologies, Inc., and JPM Capital Corporation, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on January 30, 2013.

10.29 Limited Liability Company Agreement of ORTP, LLC dated as of January 24, 2013, between Ormat Nevada, Inc., a wholly-owned subsidiary of Ormat Technologies, Inc., and JPM Capital Corporation, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on January 30, 2013.

10.30.1 Employment Agreement, dated as of February 11, 2014, between Ormat Technologies, Inc. and Isaac Angel, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 11, 2014.

10.30.2 Employment Agreement, dated as of January 6, 2013, between Ormat Systems, Ltd. and Doron Blachar, incorporated by reference to Exhibit 10.30.2 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange on February 28, 2014.

10.31.1 Amended and Restated Ormat Technologies, Inc. 2012 Incentive Compensation Plan, incorporated by reference to Exhibit 10.2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 11, 2014.

10.31.2 Form of Incentive Stock Option Agreement to Ormat Technologies, Inc. 2012 Incentive Compensation Plan, incorporated by reference to Exhibit 10.312 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 28, 2014.

10.31.3 Form of Freestanding Stock Appreciation Right Agreement to Amended and Restated Ormat Technologies, Inc. 2012 Incentive Compensation Plan, Nonqualified Stock Option Agreement to Ormat Technologies 2012 Incentive Compensation Plan, incorporated by reference to Exhibit 10.312 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 28, 2014.

10.32 Membership Interest Purchase and Sale Agreement between RET Holdings LLC and Ormat Nevada Inc., dated March 26, 2014, incorporated by reference to Exhibit 10 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on March 31, 2014.

10.33.1 JBIC Facility Agreement, dated March 28, 2014, by and among Kyuden Sarulla Pte. Ltd., OrSarulla Inc., PT Medco Geopower Sarulla, Sarulla Operations Ltd, Sarulla Power Asset Limited, Japan Bank for International Cooperation and Mizuho Bank, Ltd., dated March 28, 2014, incorporated by reference to Exhibit 10.7 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on May 9, 2014.

220

Exhibit No. Document

10.33.2 Common Terms Agreement, dated March 28, 2014, by and among Kyuden Sarulla Pte. Ltd., OrSarulla Inc., PT Medco Geopower Sarulla, Sarulla Operations Ltd, Sarulla Power Asset Limited, Japan Bank for International Cooperation, Asian Development Bank, The Bank of Tokyo-Mitsubishi UFJ, Ltd., ING Bank N.V., Tokyo Branch, National Australia Bank Limited, Mizuho Bank, Ltd., Mizuho Bank (USA), Pt. Bank Mizuho Indonesia, Société Générale, Société Générale Tokyo Branch, and Sumitomo Mitsui Banking Corporation, dated March 28, 2014, incorporated by reference to Exhibit 10.8 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on May 9, 2014.

10.33.3 Covered Lenders Facility Agreement, dated March 28, 2014, by and among Kyuden Sarulla Pte. Ltd., Orsarulla Inc., PT Medco Geopower Sarulla, Sarulla Operations Ltd, Sarulla Power Asset Limited, The Bank of Tokyo-Mitsubishi UFJ, Ltd., ING Bank N.V., Tokyo Branch, National Australia Bank Limited, Société Générale, Tokyo Branch, and Sumitomo Mitsui Banking Corporation, dated March 28, 2014, incorporated by reference to Exhibit 10.9 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on May 9, 2014.

10.33.4 ADB Facility Agreement, dated March 28, 2014, by and among Kyuden Sarulla Pte. Ltd., OrSarulla Inc., PT Medco Geopower Sarulla, Sarulla Operations Ltd, Sarulla Power Asset Limited and Asian Development Bank, dated March 28, 2014, incorporated by reference to Exhibit 10.10 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on May 9, 2014.

10.33.5 Ormat Equity Support Deed, dated March 28, 2014, by and among Ormat International, Inc., Ormat Holding Corp., OrPower 11 Inc., OrSarulla Inc., Sarulla Operations Ltd, Mizuho Bank, Ltd. and Mizuho Bank (USA), dated March 28, 2014, incorporated by reference to Exhibit 10.11 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on May 9, 2014.

10.34.1 Share Exchange Agreement and Plan of Merger dated as of November 10, 2014 by and among Ormat Technologies, Inc., Ormat Industries Ltd. and Ormat Systems Ltd., incorporated by reference to Exhibit 2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on November 17, 2014.

10.34.2 Voting Agreement dated as of November 10, 2014 by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on November 17, 2014.

10.34.3 Voting and Undertaking Agreement dated as of November 10, 2014 by and between Ormat Technologies, Inc. and FIMI ENRG, Limited Partnership and FIMI ENRG, L.P., incorporated by reference to Exhibit 10.2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on November 17, 2014.

10.34.4 Voting and Undertaking Agreement dated as of November 10, 2014 by and between Ormat Technologies, Inc. and Bronicki Investments Ltd., incorporated by reference to Exhibit 10.3 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on November 17, 2014.

10.34.5 Voting Neutralization Agreement dated as of November 10, 2014 among Ormat Technologies, Inc. and FIMI ENRG, Limited Partnership and FIMI ENRG, L.P., incorporated by reference to Exhibit 10.4 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on November 17, 2014.

10.34.6 Voting Neutralization Agreement dated as of November 10, 2014 between Ormat Technologies, Inc. and Bronicki Investments Ltd., incorporated by reference to Exhibit 10.5 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on November 17, 2014.

21.1 Subsidiaries of Ormat Technologies, Inc., incorporated by reference to Exhibit 21.1 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 28, 2006.

23.1 Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm, filed herewith.

31.1 Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.

31.2 Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.

32.1 Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.

32.2 Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.

99.1 Material terms with respect to BLM geothermal resources leases incorporated by reference to Exhibit 99.1 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 20, 2004.

221

Exhibit No. Document

99.2 Material terms with respect to BLM site leases incorporated by reference to Exhibit 99.2 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

99.3 Material terms with respect to agreements addressing renewable energy pricing and payment issues incorporated by reference to Exhibit 99.3 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

101.INS* XBRL Instance Document.*

101.SCH* XBRL Taxonomy Extension Schema Document.*

101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document.*

101.DEF* XBRL Taxonomy Extension Definition Linkbase Document.*

101.LAB* XBRL Taxonomy Extension Label Linkbase Document.*

101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document.*

* Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that the Company specifically incorporates such information by reference.

220

EX-10.1.13

Exhibit 10.1.13

AGREEMENT FOR PURCHASE OF MEMBERSHIP INTERESTS


in


ORNI 37 LLC



by and between



ORMAT NEVADA INC.



and

NORTHLEAF GEOTHERMAL HOLDINGS LLC

TABLE OF CONTENTS

		Page
Article 1	DEFINED TERMS	1
1.1	Defined Terms	1
Article 2	SALE AND PURCHASE OF MEMBERSHIP INTEREST	1
2.1	Agreement to Sell and Purchase	1
2.2	Purchase Price	1
2.3	Closing	1
2.4	Conditions Precedent to the Obligations of Purchaser	2
2.5	Conditions Precedent to the Obligations of Seller	4
Article 3	REPRESENTATIONS AND WARRANTIES	5
3.1	Representations and Warranties of Seller	5
3.2	Representations and Warranties of Purchaser	13
3.3	No Other Seller Representations	15
Article 4	CERTAIN OTHER REPRESENTATIONS, WARRANTIES AND COVENANTS	15
4.1	Regulatory Matters	15
4.2	Transfer Taxes	15
4.3	Further Action	15
4.4	[Reserved]	15
4.5	Contribution of Membership Interests	15
Article 5	INDEMNIFICATION	16
5.1	Indemnification	16
5.2	Direct Claims	16
5.3	Third Party Claims	17
5.4	After-Tax Basis	18
5.5	No Duplication	18
5.6	Sole Remedy	18
5.7	Survival	19
5.8	Final Date for Assertion of Indemnity Claims	19
5.9	Mitigation and Limitations on Losses	19
5.10	Payment of Indemnification Claims	20
5.11	Specific Performance	20
5.12	Third Party Beneficiary	20
Article 6	[RESERVED]	20
Article 7	GENERAL PROVISIONS	20
7.1	Exhibits and Schedules	20
7.2	Disclosure Schedules	20
7.3	Amendment, Modification and Waiver	20

7.4	Severability	21
7.5	Expenses	21
7.6	Parties in Interest	21
7.7	Notices	21
7.8	Counterparts	23
7.9	Entire Agreement	23
7.10	GOVERNING LAW; CHOICE OF FORUM; WAIVER OF JURY TRIAL	23
7.11	Public Announcements	23
7.12	Assignment	23
7.13	Intent of the Parties	24

Annex I	Definitions
Exhibits:
Exhibit A	Form of Assignment Agreement
Exhibit B	Form of Assignment and Assumption Agreement
Schedules:
Schedule 1	Project
Schedule 2.4(b)	Consents
Schedule 2.4(t)	Estoppels
Schedule 3.1(d)	Absence of Litigation
Schedule 3.1(g)(iv)	Audits
Schedule 3.1(g)(viii)	Powers of Attorney and Tax Rulings
Schedule 3.1(h)	Financial Statements
Schedule 3.1(i)	Compliance with Applicable Law
Schedule 3.1(j)	Environmental Matters
Schedule 3.1(k)	Permits
Schedule 3.1(l)	Insurance
Schedule 3.1(m)	Real Property
Schedule 3.1(n)	Personal Property
Schedule 3.1(p)	Material Contracts
Schedule 3.1(r)	Affiliate Transactions
Schedule 3.1(z)	Bank Accounts
Schedule 3.1(bb)	Sufficiency of Assets
Schedule 3.1(cc)	Background Materials

AGREEMENT FOR PURCHASE OF MEMBERSHIP INTERESTS

This Agreement is made and entered into as of November 22, 2016 by and between Northleaf Geothermal Holdings LLC, a Delaware limited liability company ("Purchaser"), and Ormat Nevada Inc., a Delaware corporation ("Seller"), for the sale by the Seller to the Purchaser of 36.75% of the Membership Interests (as defined below) of ORNI 37 LLC, a Delaware limited liability company (the "Company").

In consideration of the respective representations, warranties, covenants, agreements, and conditions hereinafter set forth, and other good and valuable consideration, the sufficiency of which is hereby acknowledged, the Parties hereto hereby agree as follows:

Article 1
DEFINED TERMS

1.1     Defined Terms. Capitalized terms used but not otherwise defined herein shall have the meanings given such terms in Annex I hereto, and the rules of interpretation set forth in Annex I hereto shall apply to this Agreement.

Article 2
SALE AND PURCHASE OF MEMBERSHIP INTEREST

2.1     Agreement to Sell and Purchase. Upon the terms and subject to the conditions set forth in this Agreement, Seller shall sell, assign, transfer and deliver to Purchaser on the Closing Date, and Purchaser shall purchase on the Closing Date, 36.75% of the Membership Interests in the Company, which represent a 36.75% undivided interest in the Company and the Project (the "Purchased Membership Interests"), free and clear of any Liens, for the consideration specified in Section 2.2.

2.2     Purchase Price.

(a)     The purchase price (the "Purchase Price") for the Purchased Membership Interests will be an amount equal to US$44,234,000.

(b)     The Purchase Price shall be payable by wire transfer of immediately available United States dollars to such account or accounts as Seller may designate in a written notice given to Purchaser on or prior to the Closing Date.

2.3     Closing. The closing of the purchase and sale of the Purchased Membership Interests (the "Closing") will take place (a) at the offices of Chadbourne & Parke LLP in New York, New York at 10:00 a.m. (Eastern time) on the date hereof or (b) at such other place and time as Purchaser and Seller may agree in writing.

2.4     Conditions Precedent to the Obligations of Purchaser.

The obligation of Purchaser to consummate the Closing will be subject to the satisfaction or waiver by Purchaser of each of the conditions set forth below:

(a)     Each of the representations and warranties of Seller in Section 3.1 of this Agreement and in any other Transaction Document shall be true and correct in all material respects as of the date hereof and as of the Closing Date (other than those qualified by a reference to materiality or Material Adverse Effect, which representations and warranties shall be true and correct in all respects).

(b)     All consents, approvals and filings required to be obtained or made by Seller and the Company for the Seller or the Company to execute, deliver and perform the Transaction Documents to which it is a party, including each of the consents, approvals and filings set forth on Schedule 2.4(b), shall have been obtained or made and shall be in full force and effect as of the Closing Date.

(c)     Seller shall have delivered to Purchaser one or more legal opinions of counsel to Seller and the Company, in form and substance reasonably satisfactory to Purchaser, to the effect that each of the Transaction Documents to which each of Seller or the Company is a party, and the performance of each of their respective obligations thereunder, (i) has been duly authorized, executed and delivered by such party, (ii) constitutes the valid and binding obligation of such party, as applicable, and is enforceable against such entity in accordance with its terms, (iii) does not violate any Applicable Law, decree, or judgment to which Seller or the Company or any of their respective properties are subject, (iv) does not conflict with, or cause a breach of, any provision in the Organizational Documents of Seller or the Company, (v) does not violate, result in the breach of, or constitute a default under certain examined documents, or result in the creation or imposition pursuant to the provisions of such examined documents of a Lien upon any assets of the Company, and (vi) does not require any notice, consent, approval or filing with any Governmental Authority or other Person, in each case, subject to customary qualifications, limitations and exceptions.

(d)     There shall not be any action or proceeding that has been instituted or threatened in writing by any Governmental Authority or Person against any of Purchaser, Seller, or the Company (i) that seeks to impair, restrain, prohibit or invalidate the transactions contemplated herein or in any Transaction Document, (ii) that seeks to impair, restrain, prohibit or invalidate the transactions contemplated by any Material Contract or (iii) regarding the effectiveness or validity of any governmental approvals with respect to the Company, except, in each case under clauses (ii) and (iii), to the extent such action or proceeding has not or could not reasonably be expected to have a Material Adverse Effect.

(e)     Purchaser shall have received true and complete copies of all Material Contracts.

(f)     Purchaser shall have received an endorsement of the existing title insurance policy with respect to the Project and an as-built survey with respect to the Project, each of which shall be in form and substance reasonably satisfactory to the Purchaser.

2

(g)     Seller shall have delivered to Purchaser an officer's certificate of an authorized officer of Seller (i) certifying that each of the conditions to the obligation of the Seller to consummate the Closing, set forth in Section 2.5, has been fulfilled to the satisfaction of Seller or has been waived by the Seller, (ii) certifying that each of the representations and warranties of Seller set forth in Section 3.1 is true and correct in all material respects as of the date hereof and as of the Closing Date (other than those qualified by a reference to materiality or Material Adverse Effect, which representations and warranties shall be true and correct in all respects); (iii) certifying that Seller has performed all of its obligations under this Agreement required to be performed by Seller prior to or at Closing; and (iv) attaching true and complete copies of the Organizational Documents and a good standing certificate issued as of a recent date of each of Seller and the Company, and resolutions of Seller and the Company authorizing the execution of and performance of each such entity's obligations under each of the Transaction Documents to which it is a party.

(h)     Seller shall have delivered to Purchaser a certificate of incumbency from the secretary or assistant secretary of each of Seller and the Company as to the officers of Seller and the Company who sign the Transaction Documents on behalf of each of them.

(i)     [Reserved].

(j)     Seller shall have delivered to Purchaser an affidavit of non-foreign status that complies with Section 1445 of the Code, duly executed by Seller.

(k)     Seller shall have delivered to Purchaser evidence that (i) "Commercial Operation" (as defined in the PPA) has occurred under the PPA and (ii) "Substantial Completion" (as defined in the EPC Agreement) has occurred under the EPC Agreement.

(l)     No amendments to the Material Contracts shall have been made if such amendment, modification or waiver would have been a Major Decision under the limited liability company agreement of Purchaser (as defined in the limited liability company agreement of Purchaser) and there shall be no defaults under any Material Contracts.

(m)     There shall not have occurred any events or circumstances that, individually or in the aggregate, have had or could reasonably be expected to have a Material Adverse Effect.

(n)     Seller shall have delivered to Purchaser a duly executed Assignment Agreement with respect to the assignment of the Purchased Membership Interests.

(o)     Seller shall have issued or caused the Company to issue to Purchaser a LLC Interest Certificate substantially in the form of Exhibit A to the Company LLC Agreement representing the Purchased Membership Interests.

(p)     Seller shall have delivered to Purchaser evidence that a bank account has been opened for the Company and all revenues received by the Company from and after the "Commercial Operation Date" (as defined in the PPA) have been deposited into such account.

3

(q)     Seller shall have delivered to Purchaser evidence that from and after the "Commercial Operation Date" (as defined in the PPA), the Company has not made any Restricted Payments.

(r)     [Reserved].

(s)     Seller shall have provided an IRS Form 8594 in form and substance reasonably satisfactory to Purchaser.

(t)     Seller, Purchaser, and ORPD shall have executed the Assignment and Assumption Agreement.

(u)     Seller shall have provided an estoppel duly executed by each Person and with respect to each contract set forth on Schedule 2.4(t) hereto.

(v)     Seller shall have delivered to Purchaser a duly executed Operation and Maintenance Agreement between Seller, as Operator, and the Company, as Owner, in substantially the same form as the operations and maintenance agreement for the Don A. Campbell Project (as defined in the Initial PSA) (the "O&M Agreement").

(w)     Seller shall have delivered to Purchaser an unaudited balance sheet and statements of income, changes in members' equity, and cash flow as of and for the month ended September 30, 2016 for the Company (the "Balance Sheet").

(x)     Purchaser shall have received evidence that the Company received market-based rate authorization from FERC pursuant to Section 205 of the Federal Power Act before generating test power.

(y)     Purchaser shall have received evidence that the Company has received open access and Standards of Conduct waivers from FERC prior to obtaining a 50% ownership interest in the Campbell Gen-Tie Line and any other FERC-jurisdictional shared transmission facilities covered by the Shared Facilities Agreement, and that FERC has accepted the Shared Facilities Agreement for filing.

2.5     Conditions Precedent to the Obligations of Seller.

The obligation of Seller to consummate the Closing will be subject to the satisfaction or waiver by Seller of each of the conditions set forth below:

(a)     Purchaser shall have paid to Seller the Purchase Price in the manner set forth in Section 2.2.

(b)     Each of the representations and warranties of Purchaser in Section 3.2 and in any other Transaction Document shall be true and correct in all material respects as of the Closing Date (other than those qualified by a reference to materiality or Material Adverse Effect, which representations and warranties shall be true and correct in all respects).

4

(c)     All consents, approvals and filings required to be obtained or made by Purchaser to execute, deliver and perform the Transaction Documents to which it is a party shall have been obtained or made and shall be in full force and effect as of the Closing Date.

(d)     Purchaser shall have delivered to Seller one or more legal opinions of counsel to Purchaser, in form and substance reasonably satisfactory to Seller, to the effect that each of the Transaction Documents to which Purchaser is a party (i) has been duly authorized, executed and delivered by Purchaser, (ii) constitutes the valid and binding obligation of Purchaser and is enforceable against Purchaser in accordance with its terms, (iii) does not violate any Applicable Law, decree, or judgment to which Purchaser is subject, and (iv) does not conflict with, or cause a breach of, any provision in the Organizational Documents of the Purchaser, in each case, subject to customary qualifications, limitations and exceptions.

(e)     Purchaser shall have delivered to Seller an officer's certificate of an authorized officer of Purchaser (i) certifying that each of the conditions to the obligations of Purchaser to consummate the Closing, as set forth in Section 2.4, has been fulfilled to the satisfaction of Purchaser or has been waived by Purchaser, (ii) certifying that each of the representations and warranties of Purchaser set forth in Section 3.2 are true and correct in all material respects as of the Closing Date (other than those qualified by a reference to materiality or Material Adverse Effect, which representations and warranties shall be true and correct in all respects); (iii) certifying that Purchaser has performed all of its obligations under this Agreement required to be performed by Purchaser prior to or at Closing; and (iv) attaching true and complete copies of the Organizational Documents of Purchaser and a good standing certificate issued as of a recent date, and resolutions of Purchaser authorizing the execution of the Transaction Documents to which it is a party.

(f)     Purchaser shall have delivered to Seller certificates of incumbency from the secretary or assistant secretary of Purchaser as to the officers of Purchaser who sign the Transaction Documents on behalf of Purchaser.

Article 3
REPRESENTATIONS AND WARRANTIES

3.1     Representations and Warranties of Seller. Seller represents and warrants to Purchaser as set forth below with respect to itself and the Company:

(a)     Organization, Good Standing, Etc. of Seller. Seller is a Delaware corporation, duly incorporated, validly existing and in good standing under the laws of the State of Delaware. The Company is a Delaware limited liability company, duly organized, validly existing and in good standing under the laws of the State of Delaware. Each of Seller and the Company has the relevant power and authority to own, lease and operate its properties and to carry on its business as being conducted on the date hereof. Seller has made available to Purchaser true and complete copies of the Organizational Documents of Seller and the Company.

(b)     Authority. Each of Seller and the Company has the necessary power and authority to enter into the Transaction Documents to which it is party, to perform its obligations thereunder and to consummate the transactions contemplated therein. All corporate or limited liability company actions or proceedings to be taken by or on the part of Seller and the Company to authorize and permit the due execution and valid delivery by each of Seller and the Company of the Transaction Documents to which it is a party and each other agreement instrument or certificate required to be duly executed and validly delivered by it pursuant thereto, the performance by Seller and the Company of its obligations thereunder, and the consummation by Seller and the Company of the transactions contemplated therein, have been duly and properly taken. The Transaction Documents have been duly executed and delivered by Seller and the Company, as applicable, and constitute the legal, valid, and binding obligation of Seller and the Company, as applicable, enforceable in accordance with their terms, except as such enforceability (i) may be limited by applicable bankruptcy, insolvency, reorganization, fraudulent conveyance, moratorium or other similar laws affecting the enforcement of creditors' rights and remedies generally and (ii) is subject to general principles of equity (regardless of whether enforceability is considered in a proceeding in equity or at law).

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(c)     No Conflicts; Consents.

(i)     The execution and delivery of the Transaction Documents to which each of Seller and the Company is a party and the performance by each of Seller and the Company of its respective obligations thereunder will not, (x) violate any Applicable Law to which Seller or the Company or any of their respective properties are subject, (y) conflict with or cause a breach of any provision in the Organizational Documents of Seller or the Company or (z) cause a breach of, constitute a default under, cause the acceleration of, create in any party the right to accelerate, terminate, modify or cancel, or require any authorization, consent, waiver or approval under any contract, Permit, instrument, decree, judgment or other arrangement to which Seller or the Company is a party or under which any of them is bound or to which any of their assets are subject (or result in the imposition of a Lien upon any such assets), except (in the case of this clause (z)) for any that could not reasonably be expected to have a Material Adverse Effect.

(ii)     Except as set forth on Schedule 2.4(b), no consent, approval, waiver, or authorization is required to be obtained by Seller or the Company from any Person or Governmental Authority in connection with the execution, delivery and performance by Seller and the Company of the Transaction Documents and the consummation of the transactions contemplated therein.

(d)     Absence of Litigation.

(i)     Seller has not received written notification of any actions or proceedings that have been instituted or threatened in writing by any Governmental Authority or Person against any of Seller or the Company that seeks to impair, restrain, prohibit or invalidate the transactions contemplated herein or in any Transaction Document.

(ii)     Except as set forth on Schedule 3.1(d), none of the Seller or the Company (x) is subject to any outstanding injunction, judgment, order, decree, or ruling, (y) is subject to any pending action, suit, proceeding, hearing or investigation of, in, or before any Governmental Authority or before any arbitrator, including with respect to environmental matters or (z) to Seller's Knowledge, is threatened with being made a party to any action, suit, proceeding, hearing or investigation of, in, or before any Governmental Authority or before any arbitrator including with respect to environmental matters.

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(e)     Ownership; No Other Subsidiaries.

(i)     Seller owns, of record and beneficially, 100% of the Membership Interests. The Company does not have any ownership interest in any other Person.

(ii)     There are no outstanding options, warrants, calls, puts, convertible securities or other contracts of any nature obligating Seller to issue, deliver or sell membership interests or other securities in the Company, except as provided herein, or obligating the Company to issue, deliver or sell membership interests or other securities in the Company. There are no voting trusts, proxies or other agreements or understanding in effect with respect to the voting or transfer of any of the membership interests in the Company.

(f)     Valid Interests. The Purchased Membership Interests (i) will constitute membership interests in the Company, and (ii) are being sold free and clear of any Liens, except for obligations imposed on members of the Company under the Company LLC Agreement.

(g)     Tax Matters.

(i)     (x) All income tax returns and other material Tax Returns required to be filed by or with respect to the Company and the Project have been timely filed (taking into account applicable extensions), (y) all such returns were true, correct, and complete in all material respects, and (z) all Taxes shown as due on such returns have been paid in full (other than those Taxes that are being contested in good faith, by appropriate proceedings and with adequate reserves).

(ii)     There are no outstanding agreements or waivers extending a statutory period of limitations or requests to extend a statutory period of limitations relating to Taxes due from the Company.

(iii)     The Company has not been a party to (x) a transaction that constitutes a "listed transaction" for purposes of Section 6011 of the Code and the Treasury Regulations (or a similar provision of state law) or (y) any transaction that constitutes a "reportable transaction" within the meaning of Treasury Regulations Section 1.6011-4(b) (or a similar provision of state law).

(iv)     Except as set forth on Schedule 3.1(g)(iv), there are no audits, or examinations, or matters under discussion with any Governmental Authority, with respect to Taxes relating to the Company or the Project.

(v)     There are no Liens for Taxes (other than statutory Liens for current Taxes of the Company not yet due and payable) on any assets of the Company.

(vi)     No claim has ever been made by an authority in a jurisdiction where Seller (or any of its Affiliates) or the Company does not file Tax Returns that Seller (or any of its Affiliates) or the Company is or may be subject to taxation by such jurisdiction.

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(vii)      The Company is not a party to any Tax allocation, Tax indemnity or Tax sharing agreement or similar arrangements with any Person (other than customary tax provisions in a Material Contract or Tax sharing obligations under consolidated return regulations).

(viii)     Except as set forth on Schedule 3.1(g)(viii), no power of attorney is currently in effect for income Tax purposes, and no Tax ruling has been requested of any Governmental Authority with respect to any Tax matter relating to the Company or the Project.

(ix)        Neither the Seller nor the Company is, or has been, a Depreciation Disqualified Person.

(x)       The Project is, and has been at all times, located in the United States. An election has been made under Section 168(g)(7) of the Code to depreciate the 5-year property at the Project over the class life for such property. No tax-exempt financing has been used for the Project. To Seller's Knowledge, the Project is not comprised of any imported property within the meaning of Section 168(g)(6) of the Code.

(xi)       No production tax credits pursuant to Section 45 of the Code or investment tax credits pursuant to Section 48 of the Code have been claimed on any Tax Return filed by the Seller (or its Affiliates) or the Company with respect to the Project.

(xii)      [Reserved].

(xiii)     [Reserved].

(xiv)     [Reserved].

(h)    Financial Statements. Included in Schedule 3.1(h) is a true and complete copy of the Balance Sheet. The Balance Sheet has been prepared in accordance with GAAP (subject to customary year-end adjustments and the absence of footnotes) and consistent with past fiscal periods. The Balance Sheet presents fairly in all material respects the financial position of the Company as of the date thereof. Except for the Balance Sheet, no audited or unaudited financial statements have been prepared with respect to the Company or the Project.

(i)     Compliance with Applicable Law. Except (i) as set forth on Schedule 3.1(i), (ii) with respect to Environmental Laws (which are addressed in Section 3.1(j)) and (iii) with respect to Taxes (which are addressed in Section 3.1(g)), (x) the Company is currently in material compliance with all material Applicable Law, (y) during the period that the Company has owned, directly or indirectly, the Project, the Company has been in material compliance with all material Applicable Law, except for any noncompliance that has been fully resolved or that does not present and is not reasonably likely to present any material liability to, or any material restriction on operations of, the Company, and (z) the Company has not received any written notice from a Governmental Authority of an actual or potential violation of any Applicable Law.

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(j)     Environmental Matters. Except as listed on Schedule 3.1(j), (i) to Seller's Knowledge, the Company is and has been in material compliance with all applicable Environmental Laws, (ii) none of the Seller or the Company has treated, recycled, stored, transported, handled, or Released or threatened to Release any Hazardous Substances and to Seller's Knowledge, no Hazardous Substances have been Released on the Project sites by third parties (and there are no locations or premises used by the Company where Hazardous Substances have been Released by the Company), except as could not be expected to result in material costs or material liabilities under Environmental Laws, (iii) none of the Seller (solely with respect to the Company) or the Company has received written notice from any Governmental Authority of a request for information under Section 104 of CERCLA or of an actual or potential violation of any Environmental Laws or is currently subject to or on notice with respect to any investigation, order, claim, or agreement with respect to any matter concerning a Hazardous Substance and (iv) none of the Seller or the Company has, either expressly or by operation of law, assumed any contractual liabilities under Environmental Law, including any obligation for corrective or remedial action, of any other Person relating to Environmental Law. To Seller's Knowledge, there are no facts or circumstances related to the Project (including the presence, if any, of aboveground storage tanks, known underground storage tanks, PCBs or asbestos-containing materials) or conditions at the Project site that are likely to give rise to a material violation of, or material costs or material liabilities under, applicable Environmental Laws.

(k)     Permits. All material Permits held by the Company are shown on Schedule 3.1(k). Such Permits constitute all material Permits required to own, operate and maintain the Project. Except as listed on Schedule 3.1(k), to Seller's Knowledge, (i) the Company is currently in material compliance with all material Permits, (ii) during the period in which the Company has owned, directly or indirectly, the Project, the Company has been in material compliance with all material Permits, (iii) the Company currently has in full force and effect all material Permits necessary to own, operate and maintain the Project, and (iv) the Company has not received any written notice from any Governmental Authority of an actual or potential violation of any material Permit. Except as listed on Schedule 3.1(k), all Permits are final, non-appealable, in good standing, and not subject to any modification or formal threat of revocation, challenge or suspension. As of the Closing Date, Seller has no reason to believe that the Company will not continue to be able to operate in compliance with all such Permits. True and complete copies of such Permits (without duplication of any documents delivered pursuant to Section 3.1(cc)) have been made available to Purchaser.

(l)     Insurance. Schedule 3.1(l) contains a true and complete list of all insurance policies maintained by Seller or its Affiliates (including the Company) relating to the Company or the Project, and to Seller's Knowledge (i) such insurance is adequate and customary for the business being conducted, (ii) there are no circumstances that have rendered such insurance unenforceable, and (iii) except as set forth on Schedule 3.1(l), there are no outstanding claims (or circumstances that could reasonably be expected to result in claims) under such policies. Neither the Seller nor the Company has received any written notice of cancellation of, premium increase with respect to, or alteration of coverage under, any of such policies. All premiums due and payable on such policies have been paid.

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(m)     Real Property.

(i)     All real property owned or leased by the Company or to which the Company has rights under leases, subleases, easements, licenses, governmental permits or rights of way, and the title insurance maintained by the Company with respect to all such property, is described on Schedule 3.1(m) (the "Real Property"). The Company has good and marketable title to its Real Property, including a valid leasehold interest in the real property leased by the Company, subject only to the Permitted Liens. The real property owned or leased, or in which rights are held, by the Company has been and is sufficient to enable the Company to conduct its operations prior to and as of the Closing Date and Seller has no reason to believe that such real property owned or leased, or in which rights are held, will not be sufficient to allow the Company to conduct its operations through the end of the economic useful life of the Project, including providing adequate ingress and egress from the Project in order to operate and maintain, and to produce and sell power from the Project; provided, however, that no representation is made regarding the availability, adequacy or sufficiency for any purpose whatsoever of any geothermal resource;

(ii)     The Company is not in breach of any of its obligations with respect to the Real Property, except for any breach which does not have, and could not reasonably be expected to have, a Material Adverse Effect, and neither Seller nor the Company has been informed in writing by the owner of the Real Property that the Company is in breach of its obligations with respect to the Real Property; and

(iii)     Seller has not received any written notice of any threatened or actual condemnation proceedings, and to Seller's knowledge, any such real property, in whole or in part, has not been and is not currently subject to, or threatened with, notice of condemnation proceedings, whether under the power of eminent domain or otherwise, by any Governmental Authority. All premiums with respect to the title insurance shown on Schedule 3.1(m) have been paid, no claims have been made under such title insurance and, to Seller's Knowledge, there are no circumstances that have rendered such title insurance unenforceable.

(n)     Personal Property. Schedule 3.1(n) lists all items and the location of personal property having a replacement cost of at least $1 million owned by the Company. The Company has good and marketable title to all tangible personal property owned by it and valid leasehold title to all tangible personal property leased by it. All such equipment and facilities listed on Schedule 3.1(n) and the Project is in good operating condition and repair (normal wear and tear excluded), are adequate for the uses to which they are being put and are not in need of maintenance or repairs except for maintenance and repairs in accordance with Prudent Industry Practices.

(o)     Liens. All assets owned by the Company are free and clear of all Liens, other than Permitted Liens.

(p)     Material Contracts. Schedule 3.1(p) contains a true and complete list of all Material Contracts to which the Company is a party. Each such Material Contract is in full force and effect and binding on the Company and to Seller's knowledge, on the other parties thereto, except as enforceability may be limited by applicable bankruptcy and similar laws affecting the enforcement of creditors' rights and general equitable principles. Neither the Company nor, to Seller's Knowledge, any other party to a Material Contract is in default under any Material Contract. To Seller's Knowledge, no event or circumstance has occurred that, with notice or lapse of time or both, would constitute a default under any Material Contract, result in a termination thereof, cause the acceleration or any other change of any right or obligation thereunder or cause the loss of any benefit thereunder, except where any such default, change or loss could not reasonably be expected to have a Material Adverse Effect. True and complete copies of each Material Contract (including all amendments and modifications thereto) have been made available to Purchaser.

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(q)      Employee Matters. The Company has no employees and has not maintained, sponsored, administered or participated in any employee benefit plan or arrangement, including any employee benefit plan subject to ERISA.

(r)     Affiliate Transactions. Except as listed on Part I of Schedule 3.1(r), and except for the Transaction Documents, there are no existing contracts or agreements between the Company, on the one hand, and the Seller or any other Affiliate of the Seller or any of their respective directors, officers or employees, on the other hand. Except as set forth on Part II of Schedule 3.1(r), the Company has no outstanding debt to an Affiliate thereof.

(s)      Tax Character. The Company is a "disregarded entity" for federal income tax purposes. No elections have been filed with the IRS to treat the Company as an association taxable as a corporation and the Company has never been characterized as a corporation for U.S. federal income tax purposes. The Company was originally formed as a single member limited liability company and always has been a single member limited liability company.

(t)      Regulatory Status. The Project is a Qualifying Facility.

(u)     Public Utility Holding Company. Neither the Seller nor the Company is subject to regulation as a "holding company" or a "public utility company" within the meaning of PUHCA.

(v)      Utilities. All utility services necessary for the operation of the Project for its intended purpose of producing and selling electricity are, and Seller has no reason to believe will not be, available.

(w)     Liabilities. The Company has no liabilities, whether fixed or contingent, other than (i) liabilities shown on the Balance Sheet, (ii) liabilities arising after the date of the Balance Sheet in the Ordinary Course of Business, (iii) liabilities in respect of performance under any contract in accordance with its terms, and (iv) liabilities not required to be reflected on a balance sheet prepared in accordance with GAAP.

(x)     Brokers. None of the Seller or the Company has any liability or obligation to pay fees or commissions to any broker, finder or agent with respect to the transactions contemplated by this Agreement.

(y)     Scope of Business. The Company has not engaged in any business unrelated to the development, construction, ownership, operation and maintenance of the Project and activities incidental thereto.

(z)     Bank Accounts. Schedule 3.1(z) contains a true and complete list of the names and locations of banks, trust companies and other financial institutions at which the Company maintains accounts of any nature or safe deposit boxes and the authorized signatories for each such account.

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(aa)     Solvency. None of Seller or the Company has admitted in writing its inability to pay its debts generally as they become due, is subject to a present filing against it of a petition in bankruptcy or a petition to take advantage of any insolvency act, is subject to a present assignment for the benefit of creditors, has consented to the appointment of a receiver for itself or for the whole or any substantial part of its property, or is subject to a present petition in bankruptcy, adjudication of bankruptcy or filing of a petition or answer seeking reorganization or arrangement under any bankruptcy laws.

(bb)     Sufficiency of Assets. Except as set forth in Schedule 3.1(bb), which only lists assets comprising spare parts, inventory and other ancillary equipment that is not immediately necessary for the operation of the Project at a steady state in a manner allowing compliance with all Material Contracts, as of the Closing Date, the assets of the Company, whether real, personal, tangible or intangible and whether leased, owned or licensed, comprising the Project constitute all of the assets required for or used in the operation of the Project as presently operated or proposed to be operated and no other assets are required or necessary in the operation of the Project in the Ordinary Course of Business; provided, however, that nothing contained herein shall constitute any representation or warranty regarding the sufficiency or adequacy of the geothermal resources available to the Project.

(cc)      Accuracy of Information Furnished. Seller collected and, with respect to the documents prepared by Seller, prepared the written materials contained in the virtual data room and Seller's written responses to due diligence inquiries, as set forth in Schedule 3.1(cc) (collectively, and in each case, solely as such written materials and written responses pertain solely to the Company, the "Background Materials") in good faith. The Background Materials were provided to the Purchaser by the Seller in good faith. Without limiting the effectiveness of any qualification contained in any other representation or warranty in this Section 3.1, Seller has provided all documents in Seller's possession containing material information (exclusive of documents that contain information duplicative of information contained or incorporated in any other Background Materials) relating to the Company and the Project and the Background Materials do not contain any untrue statement of a material fact concerning the Company or the Project and the transactions contemplated by this Agreement. Seller has not intentionally omitted any material fact or document from the Background Materials with the purpose of causing the Background Materials, when taken in their entirety, to be misleading. Notwithstanding anything in this Section 3.1(cc), no representation or warranty is made with respect to any Background Materials that are in the nature of projections other than that they were prepared in good faith and on the basis of assumptions that were considered reasonable in all material respects by Seller at the time made. The copies of the documents listed on Schedule 3.1(cc) that are contained in the data room are true and complete copies thereof.

(dd)     Intellectual Property. The Company, through rights granted by Seller and its Affiliates or otherwise, possesses all rights necessary to lawfully use all patents, trademarks, licenses, service marks, trade names, trade secrets, and other proprietary, or intellectual property rights that are necessary for the operation of the Project and the Company's business in the Ordinary Course of Business. To the Knowledge of Seller, the operation of the Project and the businesses as conducted by the Company does not infringe on any patent, trademark, license, service mark, trade name, trade secret, obligation of confidence or other proprietary, or intellectual property right of any Person.

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(ee)     Absence of Certain Changes or Events. Since the date of the Balance Sheet, there have not occurred any events or circumstances that individually or in the aggregate, have had or could reasonably be expected to have a Material Adverse Effect.

(ff)     Restricted Payments. The Company has not made any Restricted Payments.

3.2     Representations and Warranties of Purchaser. The Purchaser represents and warrants to Seller as follows:

(a)     Organization, Good Standing, Etc. Purchaser is a limited liability company duly organized, validly existing and in good standing under the laws of Delaware, and has the limited liability company organizational power and authority to own, lease and operate its properties and to carry on its business as being conducted on the date hereof.

(b)     Authority. Purchaser has the limited liability company organizational power and authority to enter into this Agreement and the other Transaction Documents to which it is a party, to perform its obligations hereunder and thereunder, and to consummate the transactions contemplated hereby or thereby. All actions or proceedings required to be taken by or on the part of the Purchaser to authorize and permit the due execution and valid delivery by Purchaser of this Agreement and the instruments required to be duly executed and validly delivered by Purchaser pursuant hereto and thereto, the performance by Purchaser of its obligations hereunder and thereunder, and the consummation by Purchaser of the transactions contemplated herein and therein, have been duly and properly taken. This Agreement has been duly executed and validly delivered by Purchaser and constitutes the legal, valid and binding obligation of Purchaser, enforceable in all material respects against Purchaser in accordance with its terms and conditions except as enforceability may be limited by applicable bankruptcy, insolvency, reorganization, fraudulent conveyance, moratorium and similar laws affecting the enforcement of creditors' rights and remedies generally and general equitable principles (regardless of whether enforceability is considered in a proceeding in equity or at law).

(c)     No Conflicts. The execution and delivery by Purchaser of this Agreement and the other Transaction Documents to which Purchaser is a party do not, and the performance by Purchaser of Purchaser's obligations hereunder and thereunder will not, (i) violate any Applicable Law, (ii) conflict with or cause a breach of any provision of its Organizational Documents or (iii) cause a breach of, constitute a default under, cause the acceleration of, create in any party the right to accelerate, terminate, modify or cancel, or require any authorization, consent, waiver or approval under any contract, license, instrument, decree, judgment or other arrangement to which Purchaser is a party or under which it is bound or to which any of its assets are subject (or result in the imposition of a Lien upon any such assets), except (in the case of this clause (iii)) for any that could not reasonably be expected to have a material adverse impact on Purchaser's ability to consummate the transactions contemplated by this Agreement.

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(d)     Absence of Litigation.

(i)     Purchaser has not received written notification of any actions or proceedings that have been instituted or threatened in writing by any Governmental Authority or Person against the Purchaser that seeks to impair, restrain, prohibit or invalidate the transactions contemplated herein or in any Transaction Document.

(ii)     Purchaser (x) is not subject to any pending or outstanding injunction, judgment, order, decree, ruling or charge, (y) is not subject to any pending action, suit, proceeding, hearing or investigation of, in, or before any Governmental Authority or before any arbitrator, and (z) to Purchaser's knowledge, is not threatened with being made a party to any action, suit, proceeding, hearing or investigation of, in, or before any Governmental Authority or before any arbitrator.

(e)     Accredited Investor; Information; Investment Intent. Purchaser is an "Accredited Investor" as such term is defined in Regulation D under the Securities Act of 1933, as amended (the "Securities Act"). Purchaser has had a reasonable opportunity to ask questions of and receive answers from Seller concerning Seller, the Purchased Membership Interests and the Company, and all such questions have been answered to the full satisfaction of Purchaser. Purchaser understands that the Purchased Membership Interests have not been registered under the Securities Act in reliance on an exemption therefrom, and that the Purchased Membership Interests must be held indefinitely unless the sale thereof is registered under the Securities Act or an exemption from registration is available thereunder, and that Seller is under no obligation to register the Purchased Membership Interests. Purchaser shall not sell, hypothecate or otherwise transfer the Purchased Membership Interests without registering or qualifying them under the Securities Act and applicable state securities laws unless the transfer is exempted from registration or qualification under such laws. Purchaser is purchasing the Purchased Membership Interests for its own account and not for the account of any other Person and not with a view to distribution to others.

(f)     Information and Investment Intent. Purchaser recognizes that investment in the Purchased Membership Interests involves substantial risks. Purchaser acknowledges that any financial projections that may have been provided to it are based on assumptions of future operating results developed by Seller and Seller's advisers and, therefore, represent an estimate of future results based on assumptions about certain events (many of which are beyond the control of Seller and the Company). Purchaser understands that no assurances or representations can be given that the actual results of the operations of the Company will conform to the projected results for any period. Purchaser has sufficient knowledge and experience in financial and business matters so as to be capable of evaluating the merits and risk of its investment and is able to bear the economic risk of holding the Purchased Membership Interests for an indefinite period (including total loss of its investment). Purchaser has relied solely on its own legal, tax and financial advisers for its evaluation of an investment in the Purchased Membership Interests and not on the advice of the Seller or the Company or any of their respective legal, tax or financial advisers. Notwithstanding the foregoing, nothing in this paragraph (f) shall relieve Seller or any of its affiliates of any obligations expressly imposed upon them hereunder or reduce the rights expressly granted hereunder to Purchaser and its affiliates in respect of the express representations, warranties and covenants or other agreements of Seller or its affiliates to the extent contained herein.

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(g)     Public Utility Holding Company. Purchaser is not a "holding company" within the meaning of PUHCA.

3.3     No Other Seller Representations. Except with respect to the representations and warranties of Seller and the Company in the Transaction Documents, none of Seller or the Company has made any representation or warranty, either express or implied, nor has the Purchaser relied on any representation or warranty not expressly made herein or in any other Transaction Document. The Purchaser specifically acknowledges that, except as stated in Section 3.1 and any representations and warranties made in any other Transaction Document, no representation or warranty has been made and that the Purchaser has not relied on any representation or warranty about the accuracy of any projections, estimates or budgets, future revenues, future results from operations, future cash flows, the future condition of the Project or any assets of the Company, or the future financial condition of the Company.

Article 4     
CERTAIN OTHER REPRESENTATIONS, WARRANTIES AND COVENANTS

4.1     Regulatory Matters. Promptly after the effective time of the Closing, to the extent required by Applicable Law, Seller shall file or cause to be filed with FERC a notice of self re-certification as a Qualifying Facility with respect to the Project.

4.2     Transfer Taxes. The Seller on the one hand, and the Purchaser, on the other, shall bear in equal portions and pay all sales, use, transfer, recording, gains, stock transfer and other similar taxes and fees if any, arising out of or in connection with the transactions contemplated by this Agreement and the other Transaction Documents.

4.3     Further Action. From time to time, as and when requested by any Party, the Seller and Purchaser will each execute and deliver, or cause to be executed and delivered, all such documents and instruments and will take, or cause to be taken, all such commercially reasonable actions, as such other party may reasonably deem necessary or desirable to consummate the transactions contemplated herein.

4.4     [Reserved].

4.5     Contribution of Membership Interests. Immediately following the closing of the transactions contemplated by this Agreement, Seller and Purchaser will jointly contribute the Membership Interests each respectively holds in the Company, which combine to equal one hundred percent (100%) of the Membership Interests in the Company, to ORPD pursuant to the Assignment and Assumption Agreement. The contribution of Purchaser's interest shall include an assignment to ORPD of all of Purchaser's rights and interests under this Agreement, including all representations, warranties, covenants, and indemnities of Seller hereunder. Seller hereby consents to such assignment by Purchaser of Purchaser's rights and interests hereunder and agrees that, upon such assignment, all representations, warranties, covenants, and indemnities made or given to Purchaser shall be deemed made and given to ORPD, as to the entire Membership Interest being assigned to it.

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Article 5
INDEMNIFICATION

5.1     Indemnification.  (a)  Seller agrees to indemnify, defend and hold harmless the Purchaser Indemnified Parties from and against any and all Purchaser Indemnified Costs; provided, however, that except with respect to Purchaser Indemnified Costs resulting from fraud, gross negligence or willful misconduct or failure to pay any amount due to Purchaser Indemnified Parties under any Transaction Document, in no event shall Seller's aggregate obligation to indemnify the Purchaser Indemnified Parties hereunder exceed 25% of the Purchase Price (provided, however, that (i) the 25% limitation above shall be 100% in respect of a breach of Seller's representations in Section 3.1(a), Section 3.1(b), Section 3.1(e), Section 3.1(f), Section 3.1(g) and Section 3.1(x) and (ii) there shall be no cap with respect to any Third Party Claim or any claim based on fraud, gross negligence or willful misconduct). Without regard to any of the foregoing limitations or the requirements of Section 5.1(c), Seller also agrees to indemnify, defend and hold harmless the Company from and against any and all damages, losses, claims, liabilities, Taxes, penalties, costs, and reasonable expenses (including court cost and reasonable attorneys' fees and expenses of one law firm) incurred by the Company as a result of the imposition of any liability for the Taxes of any other Person under Treasury Regulations 1.1502-6 (or any similar provision of state or local law) as a transferee or successor, by contract or otherwise ("Treas. Reg. 1.1502-6 Liability").

(b)     Purchaser agrees severally to indemnify, defend and hold harmless the Seller Indemnified Parties from and against any and all Seller Indemnified Costs; provided, however, that except with respect to Seller Indemnified Costs resulting from fraud, gross negligence or willful misconduct or failure to pay any amount due to Seller Indemnified Parties under any Transaction Document, in no event shall Purchaser's aggregate obligation to indemnify the Seller Indemnified Parties hereunder exceed 25% of the sum of the Purchase Price paid by Purchaser as of the date such indemnification obligation arises (provided, however, that the 25% limitation above shall be 100% in respect of a breach of Purchaser's representations in Section 3.2(a), Section 3.2(b), Section 3.2(c)(ii) and Section 3.2(e)).

(c)     No claim for indemnification may be made with respect to any breach (other than failure to pay an amount due) unless and until the aggregate amount of claims for which indemnification is (or previously has been) sought exceeds $1 million; provided that once such threshold amount of claims has been reached, the relevant Indemnified Party shall have the right to be indemnified for all such claims, including amounts that were not previously paid because such threshold amount had not been reached.

5.2     Direct Claims. In any case in which an Indemnified Party seeks indemnification under Section 5.1 that is not subject to Section 5.3 because no Third Party Claim is involved, the Indemnified Party shall notify the Indemnifying Party in writing of such direct claim, of any amounts which such Indemnified Party claims are subject to indemnification under the terms of this Article 5. The failure of the Indemnified Party to exercise promptness in such notification shall not amount to a waiver of such claim, except to the extent the resulting delay materially prejudices the position of the Indemnifying Party with respect to such claim.

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5.3     Third Party Claims. An Indemnified Party shall give written notice to any Indemnifying Party within 30 days after it has actual knowledge of commencement or assertion of any action, proceeding, demand, or claim by a third party (collectively, a "Third Party Claim") in respect of which such Indemnified Party may seek indemnification under Section 5.1. Such notice shall state the nature and basis of such Third Party Claim and the events and the amounts thereof to the extent known. Any failure to notify an Indemnifying Party shall not relieve such Indemnifying Party from any liability that it may have to such Indemnified Party under this Article 5, except to the extent the failure to give such notice materially and adversely prejudices such Indemnifying Party. In case any such action, proceeding or claim is brought against an Indemnified Party, so long as (a) the Indemnifying Party has acknowledged in writing to the Indemnified Party that it is liable to the Indemnified Party for such Third Party Claim pursuant to this Section 5.3, (b) in the reasonable judgment of the Indemnified Party a conflict of interest between it and the Indemnifying Party does not exist in respect of such Third Party Claim and (c) in the reasonable judgment of the Indemnified Party such Third Party Claim does not entail a material risk of criminal penalties or civil fines or non-monetary sanctions being imposed on the Indemnified Party (a "Third Party Penalty Claim") (the forgoing conditions being referred to as the "Control Conditions"), the Indemnifying Party shall be entitled to participate in and assume the defense thereof, with counsel selected by the Indemnifying Party and reasonably satisfactory to the Indemnified Party, and after notice from the Indemnifying Party to the Indemnified Party of its election so to assume the defense thereof, the Indemnifying Party shall not be liable to such Indemnified Party for any legal or other expenses subsequently incurred by the latter in connection with the defense thereof other than as expressly provided below in this Section 5.3; provided, that nothing contained herein shall permit Seller to control or participate in any Tax contest or dispute involving Purchaser or any Affiliate of Purchaser, or permit Purchaser to control or participate in any Tax contest or dispute involving Seller or any Affiliate of Seller other than the Company. In the event that (i) the Indemnifying Party advises an Indemnified Party that it will not contest a claim for indemnification hereunder, (ii) the Indemnifying Party fails, within 30 days of receipt of any indemnification notice to notify, in writing, such Indemnified Party of its election, to defend, settle or compromise, at its sole cost and expense, any such Third Party Claim (or discontinues its defense at any time after it commences such defense) or (iii) in the reasonable judgment of the Indemnified Party, a conflict of interest between it and the Indemnifying Party exists in respect of such Third Party Claim or the action or claim is a Third Party Penalty Claim, then the Indemnified Party may, at its option, defend, settle or otherwise compromise or pay such action or claim or Third Party Claim, and the Indemnifying Party shall be liable for and shall reimburse the Indemnified Party promptly and periodically for the Indemnified Party's reasonable costs and expenses arising out of the defense, settlement or compromise of any such action, claim or proceeding. In any event, unless and until the Indemnifying Party elects in writing to assume and does so assume the defense of any such claim, proceeding or action, the Indemnifying Party shall be liable for the Indemnified Party's reasonable costs and expenses arising out of the defense, settlement or compromise of any such action, claim or proceeding. The Indemnified Party shall cooperate fully with the Indemnifying Party in connection with any negotiation or defense of any such action or claim by the Indemnifying Party. The Indemnifying Party shall keep the Indemnified Party fully apprised at all times as to the status of the defense or any settlement negotiations with respect thereto. If the Indemnifying Party elects to defend any such action or claim, then the Indemnified Party shall be entitled to participate in such defense with counsel of its choice at its sole cost and expense. If any of the Control Conditions is not satisfied or becomes unsatisfied, (x) the Indemnified Party may defend against, and consent to the entry of any judgment or enter into any settlement with respect to, such Third Party Claim in any manner it may deem appropriate (and the Indemnified Party need not consult with, or obtain any consent from, any Indemnifying Party in connection therewith), (y) the Indemnifying Party will reimburse the Indemnified Party promptly and periodically for the reasonable costs of defending against such Third Party Claim (including reasonable consultant, attorney and expert witness fees, disbursements and expenses), and (z) the Indemnifying Party will remain responsible for any losses the Indemnified Party may suffer resulting from, arising out of, relating to, in the nature of, or caused by such Third Party Claim to the fullest extent provided in this Article 5. The Indemnifying Party and the Indemnified Party shall cooperate fully with each other in connection with the defense, negotiation or settlement of any such legal proceeding, claim or demand. Notwithstanding anything in this Section 5.3 to the contrary, the Indemnifying Party shall not, without the Indemnified Party's prior written consent, settle or compromise any claim or consent to entry of judgment in respect thereof which imposes any criminal liability or civil fine or sanction or equitable remedy on the Indemnified Party or which does not include, as an unconditional term thereof, the giving by the claimant or the plaintiff to the Indemnified Party, a release from all liability in respect of such claim.

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5.4     After-Tax Basis. Each Party will treat all amounts paid under any of the provisions of this Article 5 as an adjustment to the purchase price for the Purchased Membership Interests (or otherwise as a non-taxable reimbursement, contribution or return of capital, as the case may be), unless a payment is includable as income of the Indemnified Party as determined by agreement of the Parties or, if there is no agreement, by an opinion of a nationally-recognized tax counsel selected jointly by the Parties that such amount is "more likely than not" includable as income of the recipient, in which case the payment will be increased by dividing the payment by one minus the maximum federal corporate income tax rate in effect at time of payment (currently 35%). Any payment made under this Article 5 shall be reduced by the present value (using an 8% discount rate and the same assumptions about taxability and tax rates) of any federal income tax benefit to be realized by the Indemnified Party or its Affiliates by reason of the facts and circumstances giving rise to such indemnification.

5.5     No Duplication. Any liability of an Indemnifying Party to an Indemnified Party for indemnification under this Article 5 shall be determined without duplication of recovery by such Indemnified Party from such Indemnifying Party. Without limiting the generality of the prior sentence, if a statement of facts, condition or event constitutes a breach of more than one representation, warranty, covenant or agreement which is subject to the indemnification obligation in Section 5.1, only one recovery of Purchaser Indemnified Costs or Seller Indemnified Costs, as applicable, shall be allowed.

5.6     Sole Remedy. The remedies of the Parties under this Article 5 are the sole and exclusive remedies that a Party may have under this Agreement for the recovery of monetary damages with respect to any breach or failure to perform any covenant or agreement set forth in this Agreement or any breach of any representation or warranty set forth in this Agreement other than for Purchaser Indemnified Costs or Seller Indemnified Costs, as the case may be, arising from fraud, gross negligence or willful misconduct.

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5.7     Survival. All representations and warranties in this Agreement shall survive until the final date for any assertion of claims as set forth in Section 5.8.

5.8     Final Date for Assertion of Indemnity Claims.

(a)     All claims by a Purchaser Indemnified Party for indemnification pursuant to this Article 5 resulting from breaches of representations or warranties shall be forever barred unless Seller is notified on or prior to the date that is 18 months after the Closing Date, except that (i) claims by a Purchaser Indemnified Party for indemnification pursuant to this Article 5 resulting from any Treas. Reg. 1.1502-6 Liability and any breaches of representations and warranties made in Sections 3.1(b), 3.1(e), and 3.1(f) shall survive indefinitely, (ii) claims by a Purchaser Indemnified Party for indemnification pursuant to this Article 5 resulting from breaches of the representations and warranties set forth in Sections 3.1(g) or 3.1(s) shall survive for 30 days after the applicable statute of limitations on the assessment and collection of such Taxes attributable to Company items, and (iii) claims by a Purchaser Indemnified Party for indemnification pursuant to this Article 5 resulting from breaches of the representations and warranties set forth in Section 3.1(j) shall survive until the date that is 3 years after the Closing Date; provided that if written notice of a claim for indemnification has been given by such Purchaser Indemnified Party on or prior to any such date, then the obligation of the Seller to indemnify such Purchaser Indemnified Party pursuant to this Article 5 shall survive with respect to such claim until such claim is finally resolved.

(b)     All claims by a Seller Indemnified Party for indemnification pursuant to this Article 5 resulting from breaches of representations or warranties shall be forever barred unless Purchaser is notified on or prior to the date that is 18 months after the Closing Date; except that claims by a Seller Indemnified Party for indemnification pursuant to this Article 5 resulting from any breaches of representations and warranties made in Sections 3.2(b), Section 3.2(c)(ii) and Section 3.2(e) shall survive indefinitely, provided that if written notice of a claim for indemnification has been given by such Seller Indemnified Party on or prior to such date, then the obligation of the Purchaser to indemnify such Seller Indemnified Party pursuant to this Article 5 shall survive with respect to such claim until such claim is finally resolved.

5.9     Mitigation and Limitations on Losses. Notwithstanding anything to the contrary contained herein:

(a)     Reasonable Steps to Mitigate. Each of the Indemnified Parties will take, at the Indemnifying Party's cost and expense, all reasonable commercial steps identified by the Indemnifying Party to mitigate its Purchaser Indemnified Costs or Seller Indemnified Costs, as the case may be, which steps may include availing itself of any defenses, limitations, rights of contribution, claims against third Persons and other rights at law or equity. Such Indemnified Party will provide such evidence and documentation of the nature and extent of its Purchaser Indemnified Costs or Seller Indemnified Costs, as the case may be, as may be reasonably requested by the Indemnifying Party.

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(b)     Net of Insurance Benefits. The amount of Purchaser Indemnified Costs and Seller Indemnified Costs recoverable hereunder shall be net of insurance recoveries actually received by the applicable Indemnified Party from insurance policies of the Company (including under the existing title policies).

(c)     No Consequential Damages. Except to the extent awarded by a court of competent jurisdiction in a final and non-appealable judgment in connection with a Third Party Claim, fraud, gross negligence or willful misconduct, neither Purchaser Indemnified Costs nor Seller Indemnified Costs shall include, and the Indemnifying Party shall have no obligation to indemnify any Indemnified Parties for or in respect of any punitive, consequential or exemplary damages of any nature, including damages for lost profits.

5.10     Payment of Indemnification Claims. All claims for indemnification shall be paid by the Indemnifying Party in immediately available funds in United States dollars. Payments for indemnification claims shall be made promptly after any final determination of the amount of such claim is made by a court of competent jurisdiction (or by agreement of the Parties involved).

5.11     Specific Performance. Notwithstanding anything contained herein to the contrary, each of the Parties acknowledges and agrees that the other Party would be damaged irreparably in the event any of the provisions of this Agreement are not performed in accordance with their specific terms or otherwise are breached. Accordingly, each of the Parties agrees that the other Party shall be entitled to an injunction or injunctions to prevent breaches of the provisions of this Agreement and to enforce specifically this Agreement and the terms and provisions hereof in any action instituted in any court of the United States or any state thereof having jurisdiction over the Parties and the matter in addition to any other remedy to which it may be entitled, at law or in equity.

5.12     Third Party Beneficiary. The Parties acknowledge and agree that upon the effectiveness of the Assignment and Assumption Agreement, ORPD is a third party beneficiary of this Agreement with respect to the representations and warranties, covenants and indemnification provisions herein and shall have the right to enforce all of Seller's indemnification obligations hereunder directly against Seller as to the entire Membership Interest assigned to ORPD pursuant to the Assignment and Assumption Agreement.

Article 6
[RESERVED]

Article 7
GENERAL PROVISIONS

7.1     Exhibits and Schedules. All Exhibits and Schedules attached hereto are incorporated herein by reference.

7.2     Disclosure Schedules. Any matter disclosed in any section of the Schedules shall be deemed disclosed for all purposes and all sections of the Schedules to the extent it is readily apparent from a reading of the disclosure that such disclosure is applicable to such other sections.

7.3     Amendment, Modification and Waiver. This Agreement may not be amended or modified except by an instrument in writing signed by both Parties. Any failure of Purchaser or Seller to comply with any obligation, covenant, agreement, or condition contained herein may be waived only if set forth in an instrument in writing signed by the Party to be bound thereby, but such waiver or failure to insist upon strict compliance with such obligation, covenant, agreement or condition shall not operate as a waiver of, or estoppel with respect to, any other failure.

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7.4     Severability. If any term or other provision of this Agreement is invalid, illegal, or incapable of being enforced by any rule of Applicable Law, or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated herein are not affected in any manner materially adverse to any Party.

7.5     Expenses. Each Party will pay its own costs and expenses (including fees and expenses of legal counsel and other advisors or experts appointed by such Party) in connection with the preparation, negotiation and consummation of the transactions contemplated by this Agreement and the other Transaction Documents and neither Party shall have any liability therefor, whether or not the transactions contemplated herein or therein are consummated; provided, however, that Seller shall also bear the costs and expenses of the Company (including their legal fees and expenses) in connection with the Transaction Documents and the transactions contemplated thereby, including any consent, approval, filing or notification required in connection therewith. Neither Party shall be responsible for any commission, broker's fee, finder's fee or similar fee or expense of the other Party.

7.6     Parties in Interest. This Agreement shall be binding upon and, except as provided below, inure solely to the benefit of each Party and their successors and permitted assigns, and nothing in this Agreement, express or implied, is intended to confer upon any other Person (other than the Indemnified Parties as provided in Article 5 and ORPD as provided in Section 5.12) any rights or remedies of any nature whatsoever under or by reason of this Agreement.

7.7     Notices. All notices and other communications hereunder shall be in writing and shall be deemed given if delivered personally, by a nationally recognized overnight courier, by email, facsimile, or mailed by registered or certified mail (return receipt requested) to the Parties at the following addresses (or at such other address for a Party as shall be specified by like notice):

(a)          If to Seller, to:

Ormat Nevada Inc.
6225 Neil Road
Reno, Nevada 89511
Attention:     Doron Blachar
Telephone:    (775) 356-9029
Facsimile:      (775) 356-9039
Email:            dblachar@ormat.com

With a copy to:

Chadbourne & Parke LLP
1200 New Hampshire Avenue, NW
Washington, DC 20036
Attention:      Noam Ayali
Telephone:     (202) 974-5600
Facsimile:       (202) 974-5602
Email:              nayali@chadbourne.com

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(b)          If to Purchaser, to:

Northleaf Geothermal Holdings LLC
c/o Northleaf Capital Partners
79 Wellington Street West
6th Floor, Box 120
Toronto, Ontario M5K 1N9
Attention:     Olivier Laganiere
Telephone:    (416) 477-6721
Facsimile:      (416) 304-0195
Email:            olivier.laganiere@northleafcapital.com

With a copy to:

Akin Gump Strauss Hauer & Feld LLP
2629 Century Park East
Suite 2400
Los Angeles, CA 90067
Attention:      Edward Zaelke
Telephone:     (310) 229-1000
Facsimile:       (310) 229-1001
Email:             ezaelke@akingump.com

With a copy to:

Ormat Nevada Inc.
6225 Neil Road
Reno, Nevada 89511
Attention:      Doron Blachar
Telephone:     (775) 356-9029
Facsimile:       (775) 356-9039
Email:             dblachar@ormat.com

With a copy to:

Chadbourne & Parke LLP
1200 New Hampshire Avenue, NW
Washington, DC 20036
Attention:      Noam Ayali
Telephone:     (202) 974-5600
Facsimile:       (202) 974-5602
Email:             nayali@chadbourne.com

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All notices and other communications given in accordance herewith shall be deemed given (i) on the date of delivery, if hand delivered, (ii) on the date of receipt, if emailed or faxed (provided a hard copy of such transmission is dispatched by first class mail within 48 hours), (iii) 3 Business Days after the date of mailing, if mailed by registered or certified mail, return receipt requested, and (iv) 1 Business Day after the date of sending, if sent by a nationally recognized overnight courier; provided, that a notice given in accordance with this Section 7.7 but received on any day other than a Business Day or after business hours in the place of receipt, will be deemed given on the next Business Day in that place.

7.8     Counterparts. This Agreement may be executed and delivered (including by email or facsimile transmission) in one or more counterparts, all of which shall be considered one and the same agreement and shall become effective when one or more counterparts have been signed by each of the Parties and delivered to the other Parties, it being understood that all Parties need not sign the same counterpart.

7.9     Entire Agreement. This Agreement (together with the other Transaction Documents) constitutes the entire agreement of the Parties and supersedes all prior agreements, letters of intent and understandings, both written and oral, among the Parties with respect to the subject matter hereof.

7.10   GOVERNING LAW; CHOICE OF FORUM; WAIVER OF JURY TRIAL. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW THEREOF THAT WOULD RESULT IN THE APPLICATION OF THE LAWS OF ANY OTHER JURISDICTION. THE PARTIES HEREBY IRREVOCABLY SUBMIT TO THE NON-EXCLUSIVE JURISDICTION OF ANY STATE OR FEDERAL COURT IN NEW YORK WITH RESPECT TO ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT. EACH PARTY HERETO IRREVOCABLY AND UNCONDITIONALLY WAIVES TRIAL BY JURY IN ANY ACTION, SUIT OR PROCEEDING RELATING TO A DISPUTE AND FOR ANY COUNTERCLAIM WITH RESPECT THERETO.

7.11     Public Announcements. Except for statements made or press releases issued (a) in connection with any filing or disclosure under or pursuant to the securities laws, including without limitation, the rules and regulations of any stock exchange on which securities of a party or any of its Affiliates are traded, in any applicable jurisdiction, or (b) as otherwise required by Applicable Law, neither Seller nor Purchaser shall issue, or permit any of their respective Affiliates to issue, any press release or otherwise make any public statements with respect to this Agreement or the transactions contemplated hereby without the prior written consent of the other Party (not to be unreasonably withheld, conditioned or delayed) and the Parties shall cooperate as to the timing and contents of such press releases or statements.

7.12     Assignment. This Agreement and all of the provisions hereof will be binding upon and inure to the benefit of the Parties and their respective successors and permitted assigns. Neither Party may assign its rights or obligations hereunder without the prior written consent of the other Party (such consent not to be unreasonably withheld, conditioned or delayed). Any attempted assignment of this Agreement other than in strict accordance with this Section 7.12 shall be null and void and of no force or effect.

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7.13     Intent of the Parties. The Parties intend, for federal income tax purposes, that the acquisition of the Purchased Membership Interests be treated as an acquisition of undivided interests in the Company's assets directly by the Purchaser.

[Remainder of page intentionally left blank. Signature pages to follow.]

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IN WITNESS WHEREOF, each Party hereto has caused this Agreement for Purchase of Membership Interests to be signed on its behalf as of the date first written above.

ORMAT NEVADA INC., as Seller

By: /s/ Connie Stechman            

       Name: Connie Stechman

       Title: Secretary

Signature Page to Agreement for Purchase of Membership Interests (ORNI 37)

NORTHLEAF GEOTHERMAL HOLDINGS LLC,
as Purchaser

By: /s/ Katherine Gurney             

       Name: Katherine Gurney

       Title: General Counsel

By: /s/ George Zakem                  

       Name: George Zakem

       Title: Managing Officer

Signature Page to Agreement for Purchase of Membership Interests (ORNI 37)

ANNEX I
DEFINITIONS

"Affiliate" means, with respect to any Person, any other Person controlling, controlled by or under common control with such first Person. For purposes of this definition and this Agreement, (a) the term "control" (and correlative terms) means (i) the ownership of 50% or more of the equity interest in a Person, or (ii) the power, whether by contract, equity ownership or otherwise, to direct or cause the direction of the policies or management of a Person, and (b) the Company shall be deemed to be an Affiliate of Seller prior to the Closing (for purposes of representations and warranties), but shall not be deemed to be an Affiliate of Seller or Purchaser from and after the Closing for the purposes of this Agreement.

"Agreement" means this Agreement for Purchase of Membership Interests and all schedules and exhibits hereto.

"Applicable Law" means any constitution, statute, law, rule, regulation, ordinance, judgment, order, decree or governmental approval, or any directive or requirement which has the force of law, or other governmental restriction which has the force of law, or any determination by, or interpretation of any of the foregoing by, any judicial authority, applicable to and/or binding on the Seller, the Company, or the Purchaser, as the context may require, in each case as modified and/or supplemented.

"Assignment Agreement" means the Assignment of Membership Interests, by and between Seller and Purchaser, substantially in the form attached hereto as Exhibit A, dated the Closing Date.

"Assignment and Assumption Agreement" means the Assignment and Assumption Agreement, by and among Seller, Purchaser and ORPD, substantially in the form attached hereto as Exhibit B, dated the Closing Date.

"Background Materials" has the meaning set forth in Section 3.1(cc).

"Balance Sheet" has the meaning set forth in Section 2.4(v).

"Business Day" means any day other than (a) a Saturday or Sunday or (b) a day on which commercial banks in New York, New York or Toronto, Canada are authorized or required by law to be closed.

"Campbell Gen-Tie Line" means the approximately 20.5 mile long, 120 kV transmission line and associated facilities, in which each of the Company and ORNI 47 LLC have a fifty (50%) undivided interest, and which connects the Project and the Don A. Campbell Project (as defined in the Initial PSA) to the Sierra Pacific Power Company d/b/a NV Energy Excelsior 120 kV substation.

"Closing" has the meaning set forth in Section 2.3.

Annex-1

"Closing Date" means the date of the Closing.

"Code" means the United States Internal Revenue Code of 1986, as amended.

"Company" has the meaning set forth in the preamble to this Agreement.

"Company LLC Agreement" means the Amended and Restated Limited Liability Company Agreement of the Company, dated as of July 16, 2015, by and between the Seller and the Company.

"Control Conditions" has the meaning set forth in Section 5.3.

"Depreciation Disqualified Person" means (a) the United States, any state or political subdivision thereof, any possession of the United States, or any agency or instrumentality of any of the foregoing, (b) any organization that is exempted from tax imposed by the Code (including any former tax-exempt organization within the meaning of Section 168(h)(2)(E) of the Code and any tax-exempt controlled entity within the meaning of Section 168(h)(6)(F)(iii) of the Code if such entity has not made a valid election provided in Section 168(h)(6)(F)(ii) of the Code), (c) any Person who is not a United States Person, (d) any Indian tribal government described in Section 7701(a)(40) of the Code, and (e) any partnership or other pass-through entity any partner (or other holder of an equity or profits interest) of which is described in clauses (a) through (d) above; provided, however, that any such Person shall not be considered a Depreciation Disqualified Person to the extent that (i) the exception under Section 168(h)(1)(D) of the Code applies with respect to the income from the Company for that Person or (ii) the Person is described within clause (c) of this definition and the exception under Section 168(h)(2)(B)(i) of the Code applies with respect to the income from the Company for that Person.

"Environmental Law" means any and all Applicable Laws and Permits relating to the environment, the protection or preservation of human health or safety, including the health and safety of employees, the preservation or reclamation of natural resources, or the management, release or threatened release of Hazardous Substances.

"EPC Agreement" means that certain Engineering, Procurement and Construction Contract between Seller, as Contractor, and Company, as Owner, dated as of April 30, 2015.

"Equity Interests" means (a)(i) with respect to a limited liability company, any and all shares, interests, participations or other equivalents (however designated) of membership interests of such limited liability company, (ii) with respect to a partnership, any and all partnership interests, units, interests, participations shares or other equivalents (however designated) of partnership interests and (iii) with respect to a corporation, any and all capital stock, shares and other equivalents (however designated) of Equity Interests and (b) securities convertible into or exchangeable for any of the foregoing, and any and all warrants, rights or options to purchase, or obligations of a Person to sell, any of the foregoing, whether voting or nonvoting, and whether or not such shares, warrants, options, rights or other interests are authorized or otherwise existing on any date of determination.

"ERISA" means the United States Employee Retirement Income Security Act of 1974, as amended.

"Exhibits" means the Exhibits attached to this Agreement.

Annex-2

"FERC" means the Federal Energy Regulatory Commission.

"GAAP" means United States generally accepted accounting principles as recognized by the American Institute of Certified Public Accountants, as in effect from time to time, consistently applied and maintained on a consistent basis for a Person throughout the period indicated and consistent with such Person's prior financial practice.

"Governmental Authority" means any governmental department, commission, board, bureau, agency, court or other instrumentality of any country, state, province, county, parish or municipality, jurisdiction, or other political subdivision thereof.

"Hazardous Substances" means (a) any hazardous materials, hazardous wastes, hazardous substances, toxic wastes, solid wastes, and toxic substances as those or similar terms are defined under any Environmental Laws; (b) asbestos or asbestos-containing material in any form; (c) polychlorinated biphenyls ("PCBs"), or PCB-containing materials or fluids; (d) radon; (e) any petroleum, petroleum hydrocarbons, petroleum products, crude oil and any fractions or derivatives thereof; and (f) any other hazardous, radioactive, toxic or noxious substance, material, pollutant, or contaminant that, whether by its nature or its use, is subject to regulation or giving rise to liability under any Environmental Laws.

"Indemnified Party" means any Person seeking indemnification from another Person pursuant to Article 5.

"Indemnifying Party" means any Person against whom a claim for indemnification is asserted by another Person pursuant to Article 5.

"Initial PSA" means the Agreement for Purchase of Membership Interests in ORPD LLC, dated on or about February 5, 2015, by and between the Purchaser and the Seller.

"IRS" means the U.S. Internal Revenue Service.

"Knowledge", with respect to Seller, means the actual knowledge, after due inquiry, of the persons listed below and the knowledge each such Person would have as a result of reasonable inquiries of Persons with supervisory or managerial responsibilities related to such matters.

Name:
Doron Blachar
Ohad Zimron
Kyle Snyder
Scott Kessler
Zvi Krieger
Smadar Lavi

"Liens" means any liens, pledges, claims, security interests, encumbrances, easements, rights-of-way, mortgages, deeds of trust, covenants, restrictions, rights of first refusal or defects in title, or any agreement to provide any of the foregoing.

Annex-3

"Material Adverse Effect" means any event, occurrence, fact or condition that has or could reasonably be expected to have, individually or in the aggregate, a material adverse effect on (a) the business, assets, liabilities, financial condition or results of operations of the Company, taken as a whole, or (b) the ability of Seller to consummate the transactions contemplated hereby, in each case excluding any effect resulting from (i) any change in political, social, economic, industry, market or financial condition (including changes in the electric generating, transmission or distribution industry, the wholesale or retail markets for electrical power, the general state of the energy industry, including natural gas and natural gas liquid prices, the transmission system, interest rates, consumer confidence, outbreak of hostilities, terrorist activities or war), whether general or regional in nature, but excluding any such changes that are limited specifically to the Company, (ii) any change in Applicable Law or regulatory policy which does not have a disproportionate effect on the Company compared to other owners or operators of similar geothermal power projects, (iii) effects of weather or meteorological events, but excluding any such effects or events that are limited specifically to the Project, (iv) strikes, work stoppages or other labor disturbances, other than any of the foregoing occurring solely at the Company or (v) the execution or delivery of the Transaction Documents or the transactions contemplated thereby or the announcement thereof.

"Material Contract" means each of the following to which the Company is party: (a) any power purchase agreement, operation and maintenance agreement, interconnection agreement, transmission agreement, energy attribute agreement, commodity hedge agreement or similar project agreement related to the sale of electricity or transmission services of a Project, (b) any services agreement involving annual payments by or to the Company in excess of $3.5 million, (c) any agreement relating to indebtedness or any material performance obligation of the Company, including any leases, guarantees, letter of credit arrangements or bonding arrangements, in each case, in a principal amount, or that involves annual payments in an amount, of at least $3.5 million, (d) any agreement or document creating or relating to Liens on any property or assets of the Company securing any obligation created under an agreement specified in clause (c) above, (e) any engineering, construction, procurement, construction management, equipment purchase, or similar contract involving annual payments by or to the Company in excess of $3.5 million, (f) any product warranty or repair contract by or with a manufacturer or vendor of equipment owned or leased by the Company with a fair market value of more than $3.5 million, (g) any contract for the sale or purchase of any business entity, or of any property involving assets with a value in excess of $3.5 million, (h) any settlement agreement involving payments by or to the Company in excess of $3.5 million or imposing any material unperformed obligations on the Company, (i) any contracts between the Seller or any Affiliate thereof (other than the Company) and the Company, (j) any agreement regarding the sharing or allocation of Taxes, (k) any contract with payments based on the net profits of the Company (such as a royalty fee contract), (l) any contracts evidencing the real estate interests required for the ownership, use and operation of the Project, (m) any contract providing for the indemnification to or from any Person with respect to any material liabilities relating to the Company, any Project or any of their respective properties or assets, (n) any contract under which any material intellectual property is licensed to the Company, (o) any contract that provides for non-monetary obligations on the part of the Company, the non-performance of which could reasonably be expected to have a Material Adverse Effect and (p) any other contract that is expected to require payments by or to the Company in the aggregate of more than $3.5 million in any calendar year.

Annex-4

"Membership Interests" means the membership interests of the Company.

"O&M Agreement" has the meaning set forth in Section 2.4(u).

"Ordinary Course of Business" means the ordinary conduct of business consistent with past custom and practice (including with respect to quantity and frequency).

"Organizational Documents" means articles of incorporation, certificate of incorporation, charter, bylaws, articles of organization, formation or association, regulations, operating agreement, certificate of limited partnership, partnership agreement, and all other similar documents, instruments or certificates executed, adopted, or filed in connection with the creation, formation or organization of a Person, including any amendments thereto.

"ORPD" means ORPD LLC, a Delaware limited liability company.

"Party" means a party to this Agreement.

"PCBs" has the meaning set forth in the definition of "Hazardous Substances" in this Annex.

"Permits" means all licenses, franchises, permits, certificates, orders, approvals, exemptions, registrations or other authorizations from, or filings or certifications made with, Governmental Authorities, including Permits under Environmental Laws.

"Permitted Liens" means (a) Liens for any Tax not yet due or being contested in good faith and by appropriate proceedings, so long as (i) such proceedings shall not involve any substantial danger of the sale, forfeiture or loss of any Project, the sites of any Project or any easements, as the case may be, title thereto or any interest therein, and shall not interfere in any material respect with the use of any Project, any Project sites or any easements, and (ii) adequate reserves have been provided therefor to the extent required by and in accordance with GAAP, (b) carriers', warehousemen's, mechanics', materialmen's, repairmen's, employees', contractors', operators' or other similar liens or charges securing the payment of expenses not yet due and payable that were incurred in the Ordinary Course of Business of the Company, (c) trade contracts or other obligations of a like nature incurred in the Ordinary Course of Business, not to exceed $3.5 million, by the Company, (d) obligations or duties to any Governmental Authority arising in the Ordinary Course of Business (including under Permits held by the Company and under all Applicable Law), (e) obligations or duties under easements, leases or other property rights, and (f) all other encumbrances and exceptions that are incurred in the Ordinary Course of Business of each Project, are not incurred for borrowed money and do not have a material adverse effect on either the use of any assets of the Company as currently used or the value of any such assets, and which involve encumbrances or assets with an aggregate amount or value not exceeding $3.5 million.

"Person" means an individual, corporation, partnership, limited liability company, association, trust, unincorporated organization, or other entity.

Annex-5

"PPA" means that certain Don A. Campbell 2 Geothermal Energy Project Power Purchase Agreement between Southern California Public Power Authority and the Company, dated as of December 18, 2014.

"Project" means the up to 20.5 MW geothermal power project owned by the Company, as described on Schedule 1.

"Prudent Industry Practices" means, at any particular time, either (a) any of the practices, methods and acts engaged in or approved by a significant portion of the competitive geothermal power generating industry or recovered energy power generating industry, as applicable, operating in the United States at such time, or (b) with respect to any matter to which the practices referred to in clause (a) do not apply, any of the practices, methods and acts that, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good competitive electric generation business practices, reliability, safety and expedition. "Prudent Industry Practice" is not intended to be limited to the optimum practice, method or act to the exclusion of all others, but rather to be a spectrum of possible practices, methods or acts having due regard for, among other things, manufacturers' warranties, the requirements of insurance policies and the requirements of governmental bodies of competent jurisdiction.

"PUHCA" means Public Utilities Holding Company Act of 2005, as amended.

"Purchase Price" has the meaning set forth in Section 2.2(a).

"Purchased Membership Interests" has the meaning set forth in Section 2.1.

"Purchaser" has the meaning set forth in the first paragraph of this Agreement.

"Purchaser Indemnified Costs" means, subject to Article 5 of this Agreement, any and all damages, losses, claims, liabilities, demands, charges, suits, Taxes, penalties, costs, and reasonable expenses (including court costs and reasonable attorneys' fees and expenses of one law firm), for all Purchaser Indemnified Parties, incurred by any of the Purchaser Indemnified Parties resulting from or relating to (a) any breach or default by Seller of any representation, warranty, covenant, indemnity or agreement under this Agreement or any other Transaction Document or (b) any claim for fraud, gross negligence, or willful misconduct relating to this Agreement or any Transaction Document.

"Purchaser Indemnified Parties" means Purchaser and each of its Affiliates and each of their respective shareholders, members, partners, officers, directors, employees, agents, and other representatives, and their respective successors and assigns.

"Qualifying Facility" means a "qualifying facility" under the Public Utility Regulatory Policies Act of 1978, as amended, and FERC's rules and regulations promulgated thereunder at 18 C.F.R. Part 292. 1978, and FERC's rules and regulations thereunder at 18 C.F.R. Part 292.

"Real Property" has the meaning set forth in Section 3.1(m).

Annex-6

"Release" means any spilling, leaking, pumping, pouring, emitting, emptying, discharging, injecting, escaping, leaching, dumping or disposing into the environment.

"Restricted Payment" means, as to any Person, (a) the declaration or payment of any dividend on or in respect of any Equity Interests of such Person, (b) the purchase, redemption, defeasance or other acquisition or retirement of any Equity Interests of such Person, either directly or indirectly, whether in cash or property or in any shares of such Person, (c) any other distribution of or in respect of any Equity Interests of such Person, either directly or indirectly, whether in cash or property or in any shares of such Person, (d) any payment on account of, any setting apart or allocating any sum for the payment of, any dividend or distribution, or for the purchase, redemption, defeasance, retirement or other acquisition of, any Equity Interests of such Person, either directly or indirectly, whether in cash or property or in any shares of such Person or (e) the payment of any amounts, directly or indirectly, to such Person's Affiliates, other than as required under the terms of any Material Contracts in effect on the date of this Agreement or required by Applicable Law.

"Schedules" means the Schedules attached to this Agreement.

"Securities Act" has the meaning set forth in Section 3.2(e).

"Seller" has the meaning set forth in the first paragraph of this Agreement.

"Seller Indemnified Costs" means, subject to Article 5 of this Agreement, any and all damages, losses, claims, liabilities, demands, charges, suits, Taxes, penalties, costs, and reasonable expenses (including court costs and reasonable attorneys' fees and expenses of one law firm for all Seller Indemnified Parties) incurred by any of the Seller Indemnified Parties resulting from or relating to (a) any breach or default by Purchaser of any representation, warranty, covenant, indemnity or agreement under this Agreement or any other Transaction Document or (b) any claim for fraud or willful misconduct relating to this Agreement or any Transaction Document.

"Seller Indemnified Parties" means Seller and each of its Affiliates and each of their respective shareholders, members, partners, officers, directors, employees, agents, and other representatives, and their respective successors and assigns.

"Shared Facilities Agreement" means that certain Shared Facilities and Shared Premises Agreement among ORNI 47 LLC, the Company and Seller, dated as of December 19, 2014 as amended by that certain Amendment No. 1 to Shared Facilities and Shared Premises Agreement, among ORNI 47 LLC, the Company and Seller, dated as of April 30, 2015, and that certain Amendment No. 2 to Shared Facilities and Shared Premises Agreement, among ORNI 47 LLC, the Company and Seller, effective as of September 17, 2015.

"Standards of Conduct" means the standards of conduct for transmission providers located in Part 358 of FERC's regulations (18 CFR Part 358).

"Tax" or "Taxes" means any taxes, assessments, fees and other governmental charges imposed by any Governmental Authority, including income, profits, gross receipts, net proceeds, alternative or add-on minimum, ad valorem, value added, turnover, sales, use, property, personal property (tangible and intangible), environmental, stamp, leasing, lease, user, excise, duty, franchise, capital stock, transfer, registration, license, withholding, social security (or similar), unemployment, disability, payroll, employment, fuel, excess profits, occupational, premium, windfall profit, severance, estimated, unclaimed property (escheat) or other tax of any kind whatsoever, including any interest, penalty, or addition thereto, whether disputed or not.

Annex-7

"Tax Returns" means any return, report, statement, information return or other document (including any amendments thereto and any related or supporting information) filed or required to be filed with any Governmental Authority in connection with the determination, assessment, collection or administration of any Taxes or the administration of any laws, regulations or administrative requirements relating to any Taxes.

"Third Party Claim" has the meaning set forth in Section 5.3.

"Third Party Penalty Claim" has the meaning set forth in Section 5.3.

"Transaction Documents" means this Agreement and the Assignment Agreement.

"Treas. Reg. 1.1502-6 Liability" has the meaning set forth in Section 5.1.

"Treasury Regulations" means regulations promulgated by the U.S. Department of the Treasury under the Code, as such regulations are amended from time to time.

Annex-8

OTHER DEFINITIONAL PROVISIONS

(a)     All terms in this Agreement shall have the defined meanings when used in any certificate or other document made or delivered pursuant hereto unless otherwise defined therein.

(b)     As used in this Agreement and in any certificate or other documents made or delivered pursuant hereto or thereto, accounting terms not defined in this Agreement or in any such certificate or other document, and accounting terms partly defined in this Agreement or in any such certificate or other document to the extent not defined, shall have the respective meanings given to them under GAAP. To the extent that the definitions of accounting terms in this Agreement or in any such certificate or other document are inconsistent with the meanings of such terms under GAAP, the definitions contained in this Agreement or in any such certificate or other document shall control.

(c)     The words "hereof", "herein", "hereunder", and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement. Section references contained in this Agreement are references to Sections in this Agreement unless otherwise specified. The term "including" shall mean "including without limitation".

(d)     The definitions contained in this Agreement are applicable to the singular as well as the plural forms of such terms and to the masculine as well as to the feminine and neuter genders of such terms.

(e)     Any agreement, instrument or statute defined or referred to herein or in any instrument or certificate delivered in connection herewith means such agreement, instrument or statute as from time to time amended, modified or supplemented and includes (in the case of agreements or instruments) references to all attachments thereto and instruments incorporated therein.

(f)     Any references to a Person are also to its successors and permitted assigns.

(g)     All Article and Section titles or captions contained in this Agreement or in any Exhibit or Schedule referred to herein and the table of contents of this Agreement are for convenience only and shall not be deemed a part of this Agreement or affect the meaning or interpretation of this Agreement. Unless otherwise specified, all references herein to numbered Articles and Sections are to Articles and Sections of this Agreement, as applicable, and all references herein to Schedules or Exhibits are to Schedules and Exhibits to this Agreement.

(h)     Unless otherwise specified, all references contained in this Agreement, in any Exhibit or Schedule referred to herein or in any instrument or document delivered pursuant hereto to dollars or "$" shall mean United States dollars.

(i)     The Parties have participated jointly in the negotiation and drafting of this Agreement. In the event an ambiguity or question of intent or interpretation arises, this Agreement shall be construed as if drafted jointly by the Parties and no presumption or burden of proof shall arise favoring or disfavoring any Party by virtue of the authorship of any of the provisions of this Agreement.

Annex-9

Exhibit A

Form of Assignment Agreement

[FORM OF] ASSIGNMENT OF MEMBERSHIP INTERESTS

This ASSIGNMENT OF MEMBERSHIP INTERESTS, dated as of November 22, 2016 (the "Assignment Agreement"), is by and among ORMAT NEVADA INC., a Delaware corporation (the "Transferor"), NORTHLEAF GEOTHERMAL HOLDINGS LLC, a Delaware limited liability company (the "Transferee"), and ORNI 37 LLC, a Delaware limited liability company (the "Company").

W I T N E S S E T H :

WHEREAS, the Company was formed by virtue of its Certificate of Formation filed with the Secretary of State of the State of Delaware on July 21, 2009 and, until the date hereof, has been governed by the Limited Liability Company Agreement of the Company, dated as of July 21, 2009, as amended on May 25, 2010, and amended and restated on July 16, 2015 (the "Operating Agreement"), executed by the Transferor;

WHEREAS, the Transferor currently owns, of record and beneficially, 100% of the membership interests of the Company;

WHEREAS, pursuant to the Agreement for Purchase of Membership Interests in ORNI 37 LLC, dated as of November 22, 2016 (the "Purchase Agreement"), by and between the Transferor and Transferee, the Transferor has agreed to sell to the Transferee, and the Transferee has agreed to purchase from the Transferor, on the terms and subject to the conditions set forth in the Purchase Agreement, 36.75% of the membership interests of the Company, which represent a 36.75% undivided interest in the Company and the Project; and

NOW, THEREFORE, in consideration of the mutual covenants and agreements and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the undersigned do hereby agree as follows:

1.     Defined Terms. All capitalized terms not defined herein are used herein as defined in the LLC Agreement. The following terms shall have the following meanings:

a. "Encumbrance" means any charge, claim, community property interest, condition, equitable interest, lien, option, pledge, mortgage, security interest, right of first refusal or restriction of any kind, including any restriction on use, voting, transfer, receipt of income or exercise of any other attribute of ownership.

b. "Permitted Encumbrance" means Encumbrances provided for under the Transaction Documents, liens for Taxes not yet due and payable and restrictions on transfer of the Membership Interests under any applicable federal, state or foreign securities law.

c. "Project" means the up to 20.5 MW geothermal power project owned by the Company.

1

2.     Instructions to Transfer. As of the date hereof, the Transferor hereby assigns and transfers unto the Transferee complete record and beneficial ownership of 36.75% of the membership interests in the Company, together with all rights associated therewith, free and clear of any Encumbrances other than Permitted Encumbrances. The Transferor hereby irrevocably instructs the Company to register on the books of the Company the transfer to the Transferee of complete record and beneficial ownership of 36.75% of the membership interests in the Company.

3.     Further Assurances. Subject to the terms and conditions of the Purchase Agreement, at any time, or from time to time after the date hereof, the Transferor and Transferee shall, at the other's reasonable request, and at the requesting party's expense, execute and deliver such instruments of transfer, conveyance, assignment and assumption, in addition to this Assignment Agreement, and take such other action as either of them may reasonably request in order to evidence the transfer effected hereby.

4.     Successors and Assigns. This Assignment Agreement and all of the provisions hereof shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

5.     Purchase Agreement Terms. This Assignment Agreement shall, in every respect, be subject to and governed by the terms of the Purchase Agreement. To the extent this Assignment Agreement conflicts with the Purchase Agreement, the Purchase Agreement will control.

6.     Counterparts. This Assignment Agreement may be executed and delivered (including by email or facsimile transmission) in one or more counterparts, all of which shall be considered one and the same agreement and shall become effective when one or more counterparts have been signed by each of the Parties and delivered to the other Parties, it being understood that all Parties need not sign the same counterpart.

7.     Governing Law. THIS ASSIGNMENT AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW THEREOF THAT WOULD RESULT IN THE APPLICATION OF THE LAWS OF ANY OTHER JURISDICTION.

[Remainder of page intentionally left blank. Signature page to follow.]

2

IN WITNESS WHEREOF, the parties hereto have executed or caused to be executed this instrument as of the date first above written.

ORMAT NEVADA INC.,
	as the Transferor
	By:
	Name:
	Title:

[Signature Page to Assignment Agreement]

NORTHLEAF GEOTHERMAL HOLDINGS LLC,
	as Transferee
	By:
	Name:
	Title:
	By:
	Name:
	Title:

[Signature Page to Assignment Agreement]

ORNI 37 LLC,
	as the Company By: Ormat Nevada Inc., its Managing Member
	By:
	Name:
	Title:

[Signature Page to Assignment Agreement]

Exhibit B

Form of Assignment and Assumption Agreement

[See attached]

[Signature Page to Assignment Agreement]

ASSIGNMENT AND ASSUMPTION AGREEMENT

This ASSIGNMENT AND ASSUMPTION AGREEMENT dated as of November 22, 2016 (the "Agreement") is delivered by Ormat Nevada Inc., a Delaware corporation ("Ormat"), Northleaf Geothermal Holdings LLC, a Delaware limited liability company ("Northleaf", and together with Ormat, the "Assignors" and each an "Assignor") and ORPD LLC, a Delaware limited liability company ("Assignee"), in connection with that certain Amended and Restated Limited Liability Company Agreement of ORNI 37 LLC, a Delaware limited liability company (the "Company"), dated as of July 16, 2015 (the "ORNI 37 LLC Agreement"), with reference to the following facts:

A. Ormat holds a 63.25% undivided interest in the Company (the "Ormat Interest") and is a member in the Company pursuant to the terms of the ORNI 37 LLC Agreement;

B. Northleaf holds a 36.75% undivided interest in the Company (the "Northleaf Interest") and is a member in the Company pursuant to the ORNI 37 LLC Agreement;

C. Northleaf acquired the Northleaf Interest pursuant to that certain Agreement for Purchase of Membership Interests of the Company of even date herewith by and between Northleaf and Ormat (the "ORNI 37 Interest Purchase Agreement");

D. Concurrently with the execution of this Agreement, Ormat will resign as the managing member of the Company and Assignee will be appointed as the managing member of the Company; and

E. Northleaf and Ormat are each members in Assignee pursuant to that certain Limited Liability Company Agreement of Assignee dated as of April 30, 2015 (as amended, amended and restated, supplemented or otherwise modified from time to time, the "ORPD LLC Agreement").

NOW, THEREFORE, for good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the parties hereto agree as follows:

1.     Capitalized terms used herein and not otherwise defined herein shall have the meanings ascribed thereto in the ORNI 37 LLC Agreement.

2.     Under the terms of the ORNI 37 LLC Agreement, Ormat hereby assigns the Ormat Interest and Northleaf hereby assigns the Northleaf Interest to Assignee, in each case together with all rights, title and interests incident thereto. Each Assignor hereby directs that all further distributions of profit, income and return of contributions on account of such interest transferred hereby be paid to Assignee.

3.     Assignee hereby accepts the foregoing assignments of membership interests in the Company and all rights, title and interests incident thereto and hereby assumes all duties and obligations of each Assignor relating to such membership interests and arising or owing from and after the effective date hereof.

4.     By executing and delivering this Agreement Assignee shall become a party to the ORNI 37 LLC Agreement as the sole Member for all purposes of the ORNI 37 LLC Agreement, and Assignee agrees to be bound by and perform all obligations of a Member under the ORNI 37 LLC Agreement with the same force and effect as if originally named a Member thereunder.

5.     Assignee, Ormat and Northleaf agree that

a. Northleaf shall be credited with a capital contribution of $44,234,000 under the ORPD LLC Agreement for its assignment to Assignee of the Northleaf Interest and the ORNI 37 Purchase Agreement; and

b. Ormat shall be credited with a capital contribution of $76,131,000 for its assignment to Assignee of the Ormat Interest.

6.     This Agreement, the Assignment Agreement (as defined in the ORNI 37 Interest Purchase Agreement) and ORNI 37 Interest Purchase Agreement shall be deemed to be "Affiliate Contracts" under the ORPD LLC Agreement.

7.     This Agreement may be executed and delivered in one or more counterparts, all of which shall be considered one and the same agreement and shall become effective when one or more counterparts have been signed by each of the parties hereto and delivered to the other parties hereto, it being understood that all parties hereto need not sign the same counterpart.

8.     This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware.

[Remainder of page intentionally left blank. Signature pages to follow.]

IN WITNESS WHEREOF, the Assignors and Assignee have caused this Agreement to be duly executed, effective as of the date first set forth above.

ORMAT NEVADA INC., as an Assignor
By:
	Name: Connie Stechman
	Title: Secretary
NORTHLEAF GEOTHERMAL HOLDINGS LLC, as an Assignor
By:
	Name:
	Title:
By:
	Name:
	Title:

ORPD LLC, as Assignee     By: Ormat Nevada Inc., its Managing Member
By:
	Name: Connie Stechman
	Title: Secretary

Accepted and Agreed:

ORNI 37 LLC     By: Ormat Nevada Inc., its Managing Member
By:
	Name: Connie Stechman
	Title: Secretary

EX-10.1.14

Exhibit 10.1.14

AMENDED AND RESTATED
LIMITED LIABILITY COMPANY AGREEMENT

OF

OPAL GEO LLC

Dated as of December 16, 2016

TABLE OF CONTENTS

Page

ARTICLE I DEFINITIONS		1
Section 1.1	Definitions	1
Section 1.2	Other Definitional Provisions	2
ARTICLE II CONTINUATION; OFFICES; TERM		2
SectioN 2.1	Formation of the Company	2
Section 2.2	Name, Office and Registered Agent	2
Section 2.3	Purpose	3
Section 2.4	Term	3
Section 2.5	Organizational and Fictitious Name Filings; Preservation of Limited Liability	3
Section 2.6	No Partnership Intended	3
ARTICLE III RIGHTS AND OBLIGATIONS OF THE MEMBERS		4
Section 3.1	Membership Interests	4
Section 3.2	Approval Rights	4
Section 3.3	Management Rights	5
Section 3.4	Other Activities	5
Section 3.5	No Right to Withdraw	5
Section 3.6	Limitation of Liability of Members	5
Section 3.7	No Liability for Deficits	6
Section 3.8	Company Property	6
Section 3.9	Retirement, Resignation, Expulsion, Incompetency, Bankruptcy or Dissolution of a Member	7
Section 3.10	Withdrawal of Capital	7
Section 3.11	Representations and Warranties	7
ARTICLE IV CAPITAL CONTRIBUTIONS; CAPITAL ACCOUNTS		8
Section 4.1	Capital Contributions	8
Section 4.2	Capital Accounts	8
Section 4.3	Capital Contributions of the Class B Member	9
Section 4.4	Capex Contribution	11
Section 4.5	Contributions for Partnership Adjustments	11
Section 4.6	Working Capital Loans	11
Section 4.7	OFC2 Financing	11
ARTICLE V ALLOCATIONS		12
Section 5.1	Allocations	12
Section 5.2	Adjustments	13
Section 5.3	Tax Allocations	15
Section 5.4	Other Allocation Rules	16

i

ARTICLE VI DISTRIBUTIONS		17
Section 6.1	Distributions	17
Section 6.2	Withholding Taxes	18
Section 6.3	Limitation upon Distributions	18
Section 6.4	No Return of Distributions	19
Section 6.5	Substitute Payments	19
ARTICLE VII ACCOUNTING AND RECORDS		19
Section 7.1	Reports	19
Section 7.2	Books and Records and Inspection	22
Section 7.3	Bank Accounts, Notes and Drafts	23
Section 7.4	Financial Statements	24
Section 7.5	Partnership Status and Tax Elections	24
Section 7.6	Company Tax Returns	25
Section 7.7	Tax Audits	27
Section 7.8	Cooperation	29
Section 7.9	Fiscal Year	29
Section 7.10	Tax Year	29
Section 7.11	Target Internal Rate of Return Determination	30
ARTICLE VIII MANAGEMENT		34
Section 8.1	Managing Member	34
Section 8.2	Major Decisions	35
Section 8.3	Fundamental Decisions	36
Section 8.4	Insurance	36
Section 8.5	Notice of Material Breach	36
Section 8.6	Anti-Corruption Laws and Sanctions	37
ARTICLE IX TRANSFERS		37
Section 9.1	Prohibited Transfers	37
Section 9.2	Conditions Applicable to All Transfers	37
Section 9.3	Conditions Applicable to All Transfers of Class B Membership Interests	39
Section 9.4	Certain Permitted Transfers	39
Section 9.5	Right of First Offer	40
Section 9.6	Flip Purchase Option	41
Section 9.7	Buy-Out Event	42
Section 9.8	Regulatory and Other Authorizations and Consents	43
Section 9.9	Admission	43
Section 9.10	Security Interest Consent	43
Section 9.11	Regulatory Compliance	44
ARTICLE X DISSOLUTION AND WINDING-UP		45
Section 10.1	Events of Dissolution	45
Section 10.2	Distribution of Assets	45
Section 10.3	Deficit Capital Accounts	47
Section 10.4	In-Kind Distributions	48
Section 10.5	Certificate of Cancellation	49

ii

ARTICLE XI INDEMNIFICATION		49
Section 11.1	Indemnifications	49
Section 11.2	Direct Claims	49
Section 11.3	Third Party Claims	50
Section 11.4	Certain Obligation of the Class A Members	51
Section 11.5	After-Tax Basis	51
Section 11.6	No Duplication	52
Section 11.7	Survival	52
Section 11.8	Final Date for Assertion of Indemnity Claims	52
Section 11.9	Mitigation and Limitations on Losses	53
Section 11.10	Sole Remedy	53
Section 11.11	Payment of Indemnification Claims	53
ARTICLE XII COVENANTS		53
Section 12.1	Geothermal Matters	53
Section 12.2	Compliance with Senior Notes and Certain Other Material Contracts	54
Section 12.3	Certain Tax Matters	55
ARTICLE XIII MISCELLANEOUS		56
Section 13.1	Notices	56
Section 13.2	Amendment	57
Section 13.3	Partition	57
Section 13.4	Waivers and Modifications	57
Section 13.5	Severability	57
Section 13.6	Successors; No Third-Party Beneficiaries	57
Section 13.7	Entire Agreement	58
Section 13.8	Governing Law	58
Section 13.9	Further Assurances	58
Section 13.10	Counterparts	58
Section 13.11	Dispute Resolution	58
Section 13.12	Confidentiality	60
Section 13.13	Joint Efforts	61
Section 13.14	Specific Performance	61
Section 13.15	Survival	61
Section 13.16	Letter of Credit Reimbursement Obligations	61
Section 13.17	Recourse Only to Member	62

iii

ANNEX I Definitions

SCHEDULES

Schedule 1 Project Companies and Projects

Schedule 4.2(d) Capital Accounts

Schedule 4.3(b) Deferred Contributions Schedule

Schedule 8.1(a) Managing Member Responsibilities

Schedule 8.4 Insurance

Schedule 9 Transfer Representations and Warranties

EXHIBITS

Exhibit A [Reserved]

Exhibit B Form of Certificate for Class A Membership Interest

Exhibit C Form of Certificate for Class B Membership Interest

Exhibit D Form of Operations Report

Exhibit E Form of Distribution Report

Exhibit F Form of Working Capital Loan Note

Exhibit G Form of Production Report

iv

Amended and Restated
LIMITED LIABILITY COMPANY AGREEMENT

OF

OPAL GEO LLC

This Amended and Restated Limited Liability Company Agreement (this “Agreement”) of Opal Geo LLC, a Delaware limited liability company (the “Company”), dated as of December 16, 2016 (the “Effective Date”), between OrLeaf LLC, a Delaware limited liability company (“OrLeaf”) and JPM Capital Corporation, a Delaware corporation (“JPM”), is adopted, executed and agreed to, for good and valuable consideration, by the Members (as defined below).

Preliminary Statements

1.     The Company was formed by the filing of its Certificate of Formation with the Secretary of State of the State of Delaware on November 17, 2016 (the “Certificate of Formation”).

2.     The Company owns one hundred percent (100%) of the limited liability interests in OFC 2 LLC (the “Intermediate Company”) as described in Schedule 1.A hereto.

3.     The Company owns, directly or indirectly, an interest in each of the limited liability companies listed in Schedule 1.B hereto, as further described in Schedule 1.B. The companies listed on Schedule 1.B are collectively referred to as the “Project Companies” and along with the Intermediate Company are collectively referred to as the “Subject Companies”, and individually as a “Subject Company.” Each of the Project Companies owns and operates one or more geothermal power projects (collectively, the “Projects”), as further described on Schedule 1.B.

4.     Pursuant to the Equity Contribution Agreement between Ormat, OrLeaf and JPM, dated as of December 16, 2016 (the “Contribution Agreement”), JPM agreed to make a capital contribution to the Company in exchange for one hundred percent (100%) of the Class B Membership Interests (as defined below) in the Company in accordance with the Contribution Agreement and JPM will be admitted as a Member of the Company.

NOW, THEREFORE, in consideration of the mutual covenants and agreements contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Members hereby agree to adopt this Agreement with respect to various matters relating to the Company and the Members to read as follows:

ARTICLE I
DEFINITIONS

Section 1.1     Definitions. Capitalized terms used but not otherwise defined herein shall have the meanings given to such terms in Annex I hereto.

Section 1.2     Other Definitional Provisions.

(a)     All terms in this Agreement shall have the defined meanings when used in any certificate or other document made or delivered pursuant hereto unless otherwise defined therein.

(b)     As used in this Agreement and in any certificate or other documents made or delivered pursuant hereto or thereto, accounting terms not defined in this Agreement or in any such certificate or other document, and accounting terms partly defined in this Agreement or in any such certificate or other document to the extent not defined, shall have the respective meanings given to them under GAAP. To the extent that the definitions of accounting terms in this Agreement or in any such certificate or other document are inconsistent with the meanings of such terms under GAAP, the definitions contained in this Agreement or in any such certificate or other document shall control.

(c)     The words “hereof,” “herein,” “hereunder,” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement. Section references contained in this Agreement are references to Sections in this Agreement unless otherwise specified. The term “including” shall mean “including without limitation.”

(d)     The definitions contained in this Agreement are applicable to the singular as well as the plural forms of such terms and to the masculine as well as to the feminine and neuter genders of such terms.

(e)     Any date specified for action that is not a Business Day shall mean the first Business Day after such date.

(f)     Any agreement, instrument or statute defined or referred to herein or in any instrument or certificate delivered in connection herewith means such agreement, instrument or statute as from time to time amended, modified or supplemented and includes (in the case of agreements or instruments) references to all attachments thereto and instruments incorporated therein.

(g)     Any references to a Person are also to its permitted successors and assigns.

ARTICLE II
CONTINUATION; OFFICES; TERM

Section 2.1     Formation of the Company. The Company was formed as a Delaware limited liability company by the filing of the Certificate of Formation, dated as of November 17, 2016 (the “Formation Date”), with the Secretary of State of the State of Delaware pursuant to the Act.

Section 2.2     Name, Office and Registered Agent.

(a)     The name of the Company shall be “Opal Geo LLC” or such other name or names as may be agreed to by the Members from time to time. The principal office of the Company shall be 6225 Neil Road, Suite 300, Reno, NV 89511-1136. The Managing Member may at any time change the location of such office to another location, provided that the Managing Member gives prompt written notice of any such change to the Members and the registered agent of the Company.

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(b)     The registered office of the Company in the State of Delaware is located at c/o HIQ Corporate Services, Inc., 3500 South Dupont Highway, Dover, Delaware 19901. The registered agent of the Company for service of process at such address is HIQ Corporate Services, Inc. The registered office and registered agent may be changed by the Managing Member at any time in accordance with the Act provided that the Managing Member gives prompt written notice of any such change to all Members. The registered agent’s primary duty as such is to forward to the Company at its principal office and place of business any notice that is served on it as registered agent.

Section 2.3     Purpose. The nature of the business or purpose to be conducted or promoted by the Company is: (i) to acquire, own, hold or dispose of, directly or indirectly, the limited liability company interests in the Subject Companies and/or the Projects; (ii) to enter into the Transactions Documents to which it is a party, and to engage in the transactions contemplated by the Transaction Documents; and (iii) to engage in any lawful act or activity, enter into any agreement and to exercise any powers permitted to limited liability companies formed under the Act that are incidental to or necessary, suitable or convenient for the accomplishment of the purposes specified above.

Section 2.4     Term. The term of the Company commenced on November 17, 2016, and shall continue indefinitely or until the Company is dissolved in accordance with the terms hereof or as otherwise provided by law (the “Termination Date”).

Section 2.5     Organizational and Fictitious Name Filings; Preservation of Limited Liability. Prior to the Company’s conducting business in any jurisdiction other than Delaware, the Managing Member shall cause the Company to register as a foreign limited liability company and file such fictitious or trade names, statements or certificates in such jurisdictions and offices as necessary or appropriate to conduct the Company’s business. The Managing Member may take any and all other actions as may be reasonably necessary or appropriate to perfect and maintain the status of the Company as a limited liability company or similar type of entity under the laws of Delaware and any other state or jurisdiction other than Delaware in which the Company engages in business and continue the Company as a limited liability company and to protect the limited liability of the Members as contemplated by the Act.

Section 2.6     No Partnership Intended. Other than for purposes of determining the status of the Company under the Code and the applicable Treasury Regulations and under any applicable state, municipal or other income tax law or regulation, the Members intend that the Company not be a partnership, limited partnership, joint venture or other arrangement and this Agreement shall not be construed to suggest otherwise.

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ARTICLE III
RIGHTS AND OBLIGATIONS OF THE MEMBERS

Section 3.1     Membership Interests.

(a)     The Membership Interests comprise 1,000 Class A Membership Interests (the “Class A Membership Interests”) and 1,000 Class B Membership Interests (the “Class B Membership Interests”).

(b)     The Class A Membership Interests and the Class B Membership Interests shall (i) have the rights and obligations ascribed to such Membership Interests in this Agreement and the Act; (ii) be evidenced solely by certificates in the forms annexed hereto as Exhibit B and Exhibit C, respectively, or such other form as may be prescribed from time to time by any Legal Requirements; (iii) be recorded in a register of Membership Interests; (iv) be transferable only on recordation of such Transfer in the register of Membership Interests, upon compliance with the provisions of Article IX hereof and upon presentation of the certificates duly endorsed for Transfer, or accompanied by assignment documentation in accordance with Article IX hereof; (v) be “securities” governed by Article 8 of the UCC in any jurisdiction (x) that has adopted revisions to Article 8 of the UCC substantially consistent with the 1994 revisions to Article 8 adopted by the American Law Institute and the National Conference of Commissioners on Uniform State Laws and (y) whose laws may be applicable, from time to time, to the issues of perfection, the effect of perfection or non-perfection, and the priority of a security interest in Membership Interests in the Company; and (vi) be personal property.

(c)     The Company shall be entitled to treat the registered holder of a Membership Interest, as shown in the register of Membership Interests referred to in Section  of this Agreement as the Member for all purposes of this Agreement, except that the Managing Member may record in the register of Membership Interests any security interest of a secured party pursuant to any security interest permitted by this Agreement.

(d)     If a Member transfers all of its Membership Interest to another Person pursuant to and in accordance with the terms set forth in Article IX, the transferor shall automatically cease to be a Member.

Section 3.2     Approval Rights. Any authorization, consent or approval of (i) Major Decisions prior to the Flip Date and (ii) Fundamental Decisions at any time during the term hereof, shall require the affirmative authorization, consent (including, without limitation in the form provided in Section 8.2(b) or 8.3(b) of this Agreement, as applicable) or approval of Class A Members owning more than fifty percent (50%) of the outstanding Class A Membership Interests and Class B Members owning more than eighty percent (80%) of the outstanding Class B Membership Interests (each a “Super-Majority Vote”). Except for Major Decisions and Fundamental Decisions as described above, and except with respect to Other Consent Matters, which shall require a separate vote, authorization, consent or approval as and to the extent required under the relevant provision of this Agreement, no separate vote, authorization, consent or approval of either the Class A Members, acting as a class, the Class B Members, acting as a class, or the Class A Members and Class B Members acting jointly, shall be required to authorize or approve any decision, determination, action, or other matter by or of the Company, any and all of which shall be decided, determined, undertaken, or otherwise acted upon by the Managing Member as set forth in Section 8.1(a).

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Section 3.3     Management Rights. No Member other than the Managing Member shall have any right, power or authority to take part in the management or control of the business of, or transact any business for, the Company, to sign for or on behalf of the Company or to bind the Company in any manner whatsoever. Except as otherwise provided herein, the Managing Member shall not hold out or represent to any third party that any other Member has any such power or right or that any Member is anything other than a member in the Company. A Member shall not be deemed to be participating in the control of the business of the Company by virtue of its possessing or exercising any rights set forth in this Agreement or the Act or any other agreement relating to the Company.

Section 3.4     Other Activities. Notwithstanding any duty otherwise existing at law or in equity, any Member or the Managing Member may engage in or possess an interest in other business ventures of every nature and description, independently or with others, even if such activities compete directly with the business of the Company, and neither the Company nor any of the Members shall have any rights by virtue of this Agreement in and to such independent ventures or any income, profits or property derived from them.

Section 3.5     No Right to Withdraw. Except as otherwise expressly provided in this Agreement, no Member shall have any right to voluntarily resign or otherwise withdraw from the Company without the prior written consent of the remaining Members of the Company representing at least ninety-five percent (95%) of the remaining Membership Interests, in their sole and absolute discretion.

Section 3.6     Limitation of Liability of Members.

(a)     Each Member’s liability shall be limited as set forth in the Act and other applicable Legal Requirements. Except as otherwise required by the Act, the debts, obligations and liabilities of the Company, whether arising in contract, tort or otherwise, shall be the debts, obligations and liabilities solely of the Company, and the Members of the Company shall not be obligated personally for any of such debts, obligations or liabilities solely by reason of being a Member of the Company. In no event shall any Member or the Managing Member be liable under this Agreement to another Member for any lost profits of, or any consequential, punitive, special or incidental damages incurred by, such Member arising from a breach of this Agreement, provided that this shall in no way limit any such liability of a Member or the Managing Member to another Member under any other Transaction Document; provided, further, that to the extent PTCs are lost as a result of representations made by the Class A Member in the Transaction Documents not being true and correct in any respect when made or deemed made, or the breach of any covenant, obligation or agreement by Class A Member or an Affiliate of the Class A Member, the value of such lost PTCs shall be recoverable as damages and will not constitute consequential, punitive, special, incidental or exemplary damages, whether or not the underlying loss of production constitutes consequential damages for which no recovery hereunder is permitted.

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(b)     Each of the Members shall be fully protected in relying in good faith upon the records of the Company and upon such information, opinions, reports or statements presented to the Company by any other Person who is a Member, or any officer or employee of the Company, or by any other individual as to matters the Members reasonably believe are within such other individual’s professional or expert competence, including information, opinions, reports or statements as to the value and amount of the Assets, liabilities, profits or losses of the Company or any other facts pertinent to the existence and amount of Assets from which distribution to the Members might properly be paid.

(c)     To the extent that, at law or in equity, a Member, in its capacity as a member or manager of the Company or otherwise, has duties (including fiduciary duties) and liabilities relating thereto to the Company or to any Member or other Person bound by this Agreement, such Member, acting under this Agreement shall not be liable to the Company or to any Member or other Person bound by this Agreement for its good faith reliance on the provisions of this Agreement; provided, that this Section 3.6(c) shall not be construed to limit obligations or liabilities therefor, in each case as expressly stated in this Agreement or any other Transaction Document. The provisions of this Agreement, to the extent that they restrict the duties and liabilities of a Member, in its capacity as a member or manager of the Company or otherwise, otherwise existing at law or in equity, are agreed by the Members to replace such other duties and liabilities of such Member.

(d)     OrLeaf, in its capacity as a Member or Managing Member, shall not have any liability for breach of contract (except as provided in (i) and (ii) below) or breach of duties (including fiduciary duties) of a member or manager to the Company or to any other Person that is a party to or is otherwise bound by this Agreement, in each case, to the fullest extent permitted by the Act; provided, that (i) this Agreement shall not limit or eliminate liability for any (x) obligations expressly imposed on OrLeaf, as Member or Managing Member, pursuant to this Agreement or any other Transaction Document or (y) act or omission that constitutes a bad faith violation of the implied contractual covenant of good faith and fair dealing or (z) fraud, willful misconduct or gross negligence and (ii) this Section 3.6(d) shall not limit or eliminate liabilities expressly stated in this Agreement or any other Transaction Document.

(e)     Liability to the Company, any Class B Member or any other Person bound by this Agreement for damages resulting from a breach or breaches by the Operator of any of its obligations, covenants or agreements under any O&M Agreement shall be separate and distinct from liabilities of OrLeaf in its capacity as a Class A Member; and damages resulting from such breach or breaches shall not be subject to the same aggregate indemnification limitations contained in Article XI regarding Class B Member Indemnified Costs.

Section 3.7     No Liability for Deficits. Except to the extent otherwise provided by law with respect to third-party creditors of the Company and in Section 10.3(b), none of the Members shall be liable to the Company for any deficit in its Capital Account, nor shall such deficits be deemed Assets of the Company.

Section 3.8     Company Property. All property owned by the Company, whether real or personal, tangible or intangible and wherever located, shall be deemed to be owned by the Company, and no Member, individually, shall have any ownership of such property.

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Section 3.9     Retirement, Resignation, Expulsion, Incompetency, Bankruptcy or Dissolution of a Member. The retirement, resignation, expulsion, Bankruptcy or dissolution of a Member shall not, in and of itself, dissolve the Company. The successors in interest to the bankrupt Member shall, for the purpose of settling the estate, have all of the rights of such Member, including the same rights and subject to the same limitations that such Member would have had under the provisions of this Agreement to Transfer its Membership Interest. A successor in interest to a Member shall not become a substituted Member except as provided in this Agreement.

Section 3.10     Withdrawal of Capital. No Member shall have the right to withdraw capital from the Company or to receive or demand distributions (except as to distributions of Distributable Cash as set forth in Article VI) or return of its Capital Contributions until the Company is dissolved in accordance with this Agreement and applicable provisions of the Act. No Member shall be entitled to demand or receive any interest on its Capital Contributions.

Section 3.11     Representations and Warranties. Each Member hereby represents and warrants to the Company and each other Member that the following statements are true and correct as of the date it becomes a Member (both immediately before and after the time it becomes a Member):

(a)     That Member is duly incorporated, organized or formed (as applicable), validly existing, and (if applicable) in good standing under the law of the jurisdiction of its incorporation, organization or formation; if required by applicable law, that Member is duly qualified and in good standing in the jurisdiction of its principal place of business, if different from its jurisdiction of incorporation, organization or formation; and that Member has full power and authority to execute and deliver this Agreement and to perform its obligations hereunder, and all necessary actions by the board of directors, shareholders, managers, members, partners, trustees, beneficiaries, or other applicable Persons necessary for the due authorization, execution, delivery, and performance of this Agreement by that Member have been duly taken.

(b)     That Member has duly executed and delivered this Agreement and the other documents contemplated herein, and they constitute the legal, valid and binding obligation of that Member enforceable against it in accordance with their terms (except as may be limited by Bankruptcy, insolvency or similar laws of general application and by the effect of general principles of equity, regardless of whether considered at law or in equity).

(c)     That Member’s authorization, execution, delivery, and performance of this Agreement does not and will not (i) conflict with, or result in a breach, default or violation of, (A) the Organizational Documents of such Member, (B) any material contract or agreement to which that Member is a party or is otherwise subject, or (C) any law, rule, regulation, order, judgment, decree, writ, injunction or arbitral award to which that Member is subject; or (ii) require any consent, approval or authorization from, filing or registration with, or notice to, any Governmental Body or other Person, unless such requirement has already been satisfied.

(d)     That Member is a “United States person” within the meaning of Section 7701(a)(30) of the Code.

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(e)     That Member is an Unrelated Person.

(f)     That either (i) no part of the aggregate Capital Contribution made by that Member, constitutes Assets of any “employee benefit plan” within the meaning of Section 3(3) of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), or other “benefit plan investor” (as defined in U.S. Department of Labor Reg. §§2510.3-101 et seq.) or Assets allocated to any insurance company separate account or general account in which any such employee benefit plan or benefit plan investor (or related trust) has any interest or (ii) the source of the funding used to pay the Capital Contribution made by that Member is an “insurance company general account” within the meaning of Department of Labor Prohibited Transaction Exemption 95-60, issued July 12, 1995, and there is no employee benefit plan, treating as a single plan all plans maintained by the same employer or employee organization, with respect to which the amount of the general account reserves and liabilities for all contracts held by or on behalf of such plan exceeds ten percent (10%) of the total reserves and liabilities of such general account (exclusive of separate account liabilities) plus surplus, as set forth in the National Association of Insurance Commissioners “Annual Statement” filed with such Member’s state of domicile.

(g)     That Member is an “Accredited Investor” as such term is defined in Regulation D under the Securities Act of 1933, as amended (the “Securities Act”). That Member has had a reasonable opportunity to ask questions of and receive answers from the Company concerning the Membership Interests and the Company, and all such questions have been answered to the full satisfaction of that Member. That Member understands that the Membership Interests have not been registered under the Securities Act in reliance on an exemption therefrom, and that the Company is under no obligation to register the Membership Interests. That Member will not transfer the Membership Interests in violation of the Securities Act or any other applicable securities laws. That Member is purchasing the Membership Interests for its own account and not for the account of any other Person and not with a view to distribution or resale to others.

ARTICLE IV
CAPITAL CONTRIBUTIONS; CAPITAL ACCOUNTS

Section 4.1     Capital Contributions. The Class B Member will make a Capital Contribution to the Company on the Effective Date as described in Article II of the ECA. Except as provided in this Article IV and Section 10.3(b), no Member will be required to make any Capital Contributions to the Company after the Effective Date.

Section 4.2     Capital Accounts.

(a)     A capital account (a “Capital Account”) will be established and maintained for each Member. If there is more than one Member in a class, then each of the Members in that class will have a separate Capital Account.

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(b)     A Member’s Capital Account will be increased by (i) the amount of money the Member contributes to the Company, (ii) the net value of any property the Member contributes or is deemed to contribute to the Company (i.e., the fair market value of the property net of liabilities secured by the property that the Company is considered to assume or take subject to under Section 752 of the Code), and (iii) the income and gain the Member is allocated by the Company, including any income and gain that are exempted from tax. A Member’s Capital Account will be decreased by (i) the amount of Distributable Cash distributed or deemed distributed to the Member by the Company, (ii) the net value of any property distributed to the Member by the Company (i.e., the fair market value of the property net of liabilities secured by the property that the Member is considered to assume or take subject to under Section 752 of the Code), (iii) any expenditures of the Company described in Section 705(a)(2)(B) of the Code (i.e., that cannot be capitalized or deducted in computing taxable income) that are allocated to the Member; and (iv) losses and deductions that are allocated to the Member.

(c)     The Company’s property will be revalued, and the Capital Accounts of the Members will be reset to reflect that revaluation as directed by Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to the following events: (i) if any new or existing Member makes more than a de minimis Capital Contribution in exchange for a new or additional Membership Interest, (ii) if Distributable Cash or other property is distributed by the Company to a Member to redeem its Membership Interest, or (iii) if the Company is liquidated.

(d)     The Capital Account balances and Capital Interest of each Member on the Closing Date are shown in Schedule 4.2(d).

(e)     If all or a portion of a Membership Interest in the Company is Transferred in accordance with the terms of this Agreement, then the transferee will succeed to the Capital Account of the transferor to the extent it relates to the Membership Interest so Transferred.

(f)     The provisions of this Agreement relating to maintenance of Capital Accounts are intended to comply with Treasury Regulation Section 1.704-1(b), and will be interpreted and applied in a manner consistent with such Treasury Regulation or any successor provision.

Section 4.3     Capital Contributions of the Class B Member.

(a)     Subject to Section 4.3(b) below, on each Deferred Contribution Date the Class B Member shall contribute its Deferred Contribution to the Company in the amount equal to the product of the applicable Deferred Contribution Payment Rate multiplied by the MWh of Excess Production; provided that, notwithstanding anything to the contrary herein, the aggregate obligation of the Class B Member to make contributions to the Company under this Section 4.3(a) shall not exceed the Deferred Contribution Cap.

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(b)     Without limiting its obligation under Section 4.3(a), if (i) the Class B Member cannot determine the amount of the Deferred Contribution it is required to make on any Deferred Contribution Date under Section 4.3(a) because the applicable Production Report has not been delivered to such Class B Member as required pursuant to Section 7.1(f), (ii) a good faith dispute pursuant to Section 13.11(b) is ongoing with such Class B Member as to whether the Flip Date has occurred, or (iii) a good faith dispute pursuant to Section 7.1(h) is ongoing involving such Class B Member with respect to the calculation of items in a Production Report, the Class B Member’s obligation to make such Deferred Contribution (in the case of clause (i) or (ii) above) or the disputed portion of such Deferred Contribution (in the case of clause (iii) above) shall automatically be extended until the later of such Deferred Contribution Date or fifteen (15) days following the delivery of such Production Report (unless a good faith dispute is ongoing pursuant to Section 7.1(h) in respect of such Production Report) or resolution of such dispute pursuant to Section 7.1(h) or Section 13.11(b), as applicable. If the Class B Member makes a Deferred Contribution pursuant to Section 4.3(a) which constitutes an Overpayment which is later determined pursuant to Section 7.1(g) to have been greater than the amount of the Deferred Contribution required to be made pursuant to Section 4.3(a), such excess amount will be returned to such Class B Member from the Class A Member within ten (10) Business Days of such notification, and if a Class B Member makes a Deferred Contribution pursuant to Section 4.3(a) resulting in an Underpayment which is later determined pursuant to Section 7.1(g) to have been less than the amount of the Deferred Contribution required to be made pursuant to Section 4.3(a), such shortfall shall within ten (10) Business Days of such notification be contributed to the Company by such Class B Member. In addition, notwithstanding anything herein to the contrary, if (x) the Class A Member, in its capacity as the Managing Member, shall have breached Section 8.2, Section 8.3, or any covenant contained in Article XII in any material respect and such breach shall not have been cured, otherwise remedied, or waived or (y) the Class A Member shall have breached any of its representations and warranties under Article III of the Contribution Agreement, under Section 3.11 hereof or breached its covenant under Article VI of the Contribution Agreement or Article XII hereof and such breach has or is reasonably likely to have a Material Adverse Effect or has or is reasonably likely to have a materially adverse effect with respect to the Class B Member, then upon the occurrence of any of the preceding in clause (x) or (y), the Class B Member shall have no obligation to make any Deferred Contributions under Section 4.3(a) until such breach or default shall have been cured, remedied or waived, in which case, the Class B Member shall be obligated to make all Deferred Contributions which it would have been required to make under Section 4.3(a) no later than 30 days following the cure, remedy or waiver of such breach or default and no interest shall accrue on any such obligations during such period.

(c)     In the event that the Class B Member fails to make any Deferred Contribution under Section 4.3(a) within 20 Business Days from the date such Deferred Contribution is required to be made in accordance with Section 4.3(a) (subject to any extension or suspension of such obligation under Section 4.3(b) or Section 4.7, or amounts subject to any ongoing dispute pursuant to Section 7.1(h) or Section 13.11(b), a “Class B Contribution Default”) (such undisputed amount being a “Class B Defaulted Contribution”), the Company shall distribute to the Class A Member the distributions of Distributable Cash otherwise distributable (assuming no Class B Defaulted Contribution had occurred) to the defaulting Class B Members pursuant to Section 6.1 in an amount up to the Class B Defaulted Contribution and thereby reduce the amounts otherwise owed by the Class B Member with respect to the Class B Defaulted Contribution. Effective immediately upon the occurrence of a Class B Contribution Default, and for as long thereafter as such Class B Contribution Default shall be continuing, the Class B Defaulted Contribution then due and payable shall bear interest at a rate that is equal to eight percent (8%), calculated on a per annum basis, and such amounts shall be immediately due and payable by the Class B Members upon the Class A Member’s demand.

(d)     All payments required to be made under this Section 4.3 shall be made by wire transfer in immediately available funds.

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Section 4.4     Capex Contribution. OrLeaf, or any Affiliate of OrLeaf, may make (but will have no obligation to make) Capital Contributions to the Company or any Subject Company for any capital expenditures that the Managing Member determines (in its sole discretion and without any requirement for consent or other action by any Class B Member) is reasonable or advisable (any such contribution, a “Capex Contribution”).

Section 4.5     Contributions for Partnership Adjustments. In the event the Company receives a notice of final partnership adjustment with respect to which an “imputed underpayment” within the meaning of Section 6225(b) of Title XI of the Bipartisan Budget Act of 2015 (P.L. 114-74) (“Title XI”) and the Partnership Representative does not elect the application of Section 6226 of Title XI, each Member will be obligated to make a Capital Contribution to the Company in an amount equal to its allocable share of the imputed underpayment (and any associated penalties, interest and additions to tax, as applicable) as determined by the Partnership Representative and calculated in a manner that takes into account the allocation of tax risks between the Members reflected in this Agreement and agreed by the Class B Member; provided, any dispute among the Members with respect to any such amount shall be subject to a dispute resolution process consistent with Section 13.11.

Section 4.6     Working Capital Loans. OrLeaf, or any Affiliate of OrLeaf, may make (but will have no obligation to make) loans to the Company or any Subject Company, when and as needed (as determined by the Managing Member and without any requirement for consent or other action by any Class B Member), sufficient to cover working capital, maintenance and other similar expenditure needs of the Company or any of the Subject Companies in an aggregate principal amount outstanding at any time not to exceed ten million dollars ($10,000,000) for the Company and all Subject Companies, combined (any such loan, a “Working Capital Loan”). All Working Capital Loans shall be unsecured and repaid out of Distributable Cash of the Company (if the Company is the borrower) or available cash flow of the relevant Subject Company (if such Subject Company is the borrower) before any distributions of Distributable Cash to members of such entity. Any Working Capital Loans made by OrLeaf or an Affiliate of OrLeaf shall (a) be unsecured and evidenced by a note substantially in form of Exhibit F hereto and (b) otherwise be on terms equivalent in all material respects to loans that would be available from a third party lender that is not an Affiliate of OrLeaf.

Section 4.7     OFC2 Financing. Notwithstanding anything to the contrary in this Agreement, the Members agree, that:

(a)     upon any draw upon or depletion of any security (such as a letter of credit) or reserve amount required to be provided and maintained under any of the OFC2 Note Purchase Agreement, OFC2 Indenture or any other Loan Document (as defined in the OFC2 Note Purchase Agreement), then unless otherwise agreed by the consent of Class B Members owning more than 80% of the Class B Membership Interests following good faith review of the consent request, (x) no Distributable Cash will be distributed to the Class A Member and (y) such Distributable Cash that would otherwise have been distributed to the Class A Member will instead be used to replenish, replace or reinstate any such security or reserve amount; provided, that, if such Distributable Cash is not adequate to cause the security or reserve amount to be replenished, replaced or reinstated in full within 30 days, then the Class B Member may (but shall not be obligated to) advance the funds needed to replenish, replace or reinstate the full balance of the security or reserve amount then outstanding (a “Class B Member Loan”), and such Class B Member Loan shall be unsecured and shall bear interest at a rate equal to the lesser of (A) ten percent (10%) or (B) the highest rate of interest that may be charged by the Class B Member in accordance with applicable law. Interest on and the principal amount of any Class B Member Loan shall be paid on each Distribution Date from Distributable Cash prior to the making of any payments provided for in Section 6.1. Interest on any Class B Member Loan shall accrue, and if not paid in accordance with the immediately preceding sentence of this Section 4.7(a), be compounded to the principal amount thereof on each Distribution Date;

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(b)     following an OFC2 Distribution Block, and not withstanding anything to the contrary in Section 4.7(a) above, (i) an amount up to (63.25%) of Distributable Cash generated by ORNI 37 that would otherwise have been distributed to the Class A Member shall be used to remedy the event or events giving rise to the OFC2 Distribution Block (other than with respect to an OFC2 Distribution Block as a result of Section 10.5(a)(viii) of the OFC2 Note Purchase Agreement) and (ii) the Class B Member shall not be obligated to make Deferred Contributions under Section 4.3 (and no interest shall accrue on any such withheld Deferred Contributions) until such time that the event or events giving rise to such OFC2 Distribution Block are remedied, at which time the Class B Member shall be obligated to make within 30 days all Deferred Contributions which it would have otherwise been required to make under Section 4.3(a); and

(c)     following an OFC2 Foreclosure, (i)  an amount up to (63.25%) of Distributable Cash generated by ORNI 37 that would otherwise have been distributed to the Class A Member will be distributed to the Class B Member on each Distribution Date following such OFC2 Foreclosure until the earlier to occur of the Flip Date and achievement of the Target Internal Rate of Return (for the avoidance of doubt, using the calculation rules and conventions in Section 7.11(a) through (d)) and (ii) the Class B Member shall not be obligated to make Deferred Contributions under Section 4.3.

ARTICLE V
ALLOCATIONS

Section 5.1     Allocations. For purposes of maintaining Capital Accounts, except as otherwise provided in Section 10.2 and after giving effect to Section 5.2, all items of Company income and loss, gain, deduction and credit (including items associated with any interest deductions) will be allocated among the Members as follows:

(a)     for the period from the Closing Date through the Target Flip Date, ninety-nine percent (99%) to the Class B Member and one percent (1%) to Class A Member;

(b)     after the Target Flip Date (if the Flip Date has not yet occurred) until the Flip Date, (i) ninety-nine percent (99%) to the Class B Member and one percent (1%) to Class A Member for so long as any one of the PTC Eligible Projects is generating PTCs and (ii) five percent (5%) to the Class B Member and ninety-five percent (95%) to Class A Member if PTCs are no longer available to any of the Projects; and

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(c)     from and after the Flip Date, five percent (5%) to the Class B Member and ninety-five percent (95%) to Class A Member.

(d)     Notwithstanding the foregoing, if the Class B Member would have a deficit Capital Account balance in excess of the amounts the Class B Member is obligated to restore pursuant to the penultimate sentence of Treasury Regulations Section 1.704.2(g)(1) and 1.704-2(i)(5) as of the end of any Tax Year ending on or after the Flip Date, income and gain of the Company (but not loss or deductions of the Company) shall be allocated ninety-nine percent (99%) to the Class B Member up to the amount of such deficit, and one percent (1%) to the Class A Member until the Class B Member’s deficit Capital Account balance is not in excess of the amounts that such Class B Member is deemed obligated to restore.

Section 5.2     Adjustments. The following adjustments will be made in the allocations in Section 5.1 in the following order of priority to comply with Treasury Regulation Section 1.704-1(b):

(a)     Except as provided in Treasury Regulations Section 1.704-2(f), if there is a net decrease in Company Minimum Gain during any Tax Year, each Member shall be allocated Company items of income and gain for such Tax Year (and, if necessary subsequent Tax Years) in an amount equal to such Member’s share of the net decrease in Company Minimum Gain, determined in accordance with Treasury Regulations Section 1.704-2(g). Allocations pursuant to the previous sentence shall be made in proportion to the respective amounts required to be allocated to each Member pursuant thereto. The Company items to be so allocated shall be determined in accordance with Treasury Regulations Sections 1.704-2(f)(6) and 1.704-2(j)(2). This Section 5.2(a) is intended to comply with the minimum gain chargeback requirement in Treasury Regulations Section 1.704-2(f) and shall be interpreted consistently therewith. For each Tax Year in which there is an increase in Company Minimum Gain, each Member’s share of such increase shall be determined pursuant to Treasury Regulations Section 1.704-2(g)(1).

(b)     If there is a net decrease in Minimum Gain Attributable to Member Nonrecourse Debt during any Tax Year, determined in accordance with Treasury Regulation Section 1.704-2(i)(3), then, except as provided in Treasury Regulation Section 1.704-2(i)(4), each Member who has a share of Minimum Gain Attributable to Member Nonrecourse Debt, determined in accordance with Treasury Regulation Section 1.704-2(i)(5), will be allocated items of income and gain for such Tax Year (and, if necessary, subsequent Tax Years) in an amount equal to such Member’s share of the net decrease in Minimum Gain Attributable to Member Nonrecourse Debt. The items of Company income or gain to be allocated will be determined in accordance with Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2). This subsection (b) is intended to comply with Treasury Regulation Section 1.704-2(i)(4) and will be applied and interpreted in accordance with such Treasury Regulation.

(c)     Nonrecourse Deductions, to the extent they exist and can be separately allocated, will be allocated among the Members in the same proportions as the allocations of income and loss were made for the Tax Year pursuant to Section 5.1(a) through (c), as in effect at the time the Nonrecourse Deduction arises, or if applicable, Section 10.2(a)(iv), as in effect at the time the Nonrecourse Deduction arises. The Members intend that these allocations will follow the allocations of significant items of partnership income and loss allocable to property securing the indebtedness and will be reasonably consistent with allocations that have substantial economic effect and in compliance with Treasury Regulation Section 1.704-2(b) and (e)(2).

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(d)     Any Member Nonrecourse Deductions will be allocated in accordance with Treasury Regulation Section 1.704-2(i) to the Member who bears the economic risk of loss for the Member Nonrecourse Debt to which such Member Nonrecourse Deductions relate.

(e)     In the event any Member unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), (5) or (6) resulting in any deficit in such Member’s Adjusted Capital Account, items of income and gain will be specially allocated to such Member in any amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations, the deficit in such Member’s Adjusted Capital Account as quickly as possible. The items of income or gain to be allocated will be determined in accordance with Treasury Regulation Section 1.704-1(b)(2)(ii)(d). This subsection (e) is intended to comply with Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and will be applied and interpreted in accordance with such Treasury Regulation; provided, that the special allocation pursuant to this subsection (e) will be made only if and to the extent that such Member would have a deficit in its Adjusted Capital Account balance after all of the other special allocations provided for in this Section 5.2 have been tentatively made as if this subsection (e) were not in this Agreement.

(f)     No items of loss or deduction will be allocated to any Member to the extent that any such allocation would cause the Member to have, or increase the amount of, an existing deficit in such Member’s Adjusted Capital Account at the end of any Tax Year. All items of loss or deduction in excess of the limitation set forth in this subsection (f) will be allocated among such other Members that have positive Adjusted Capital Accounts, pro rata, in proportion to such Adjusted Capital Accounts, until each such Member’s positive Adjusted Capital Account is reduced to zero; provided, that this subsection (f) will apply only to the extent that such Member would have a deficit in its Adjusted Capital Account after all of the other allocations provided for in this Section 5.2 have been tentatively made as if this subsection (f) and subsection (e) above were not in this Agreement.

(g)     In the event any Member has a deficit in such Member’s Adjusted Capital Account at the end of any Tax Year, each such Member will be specially allocated items of income and gain as quickly as possible to eliminate such deficit in its Adjusted Capital Account; provided, that an allocation pursuant to this subsection (g) will be made if and only to the extent that such Member would have a deficit in its Adjusted Capital Account in excess of such sum after all of the other allocations provided for in Section 5.1 and this Section 5.2 have been tentatively made as if this subsection (g) and subsection (e) above were not in this Agreement.

(h)     To the extent an adjustment to the adjusted tax basis of any Company Asset pursuant to Sections 734(b) or 743(b) of the Code is required to be taken into account in determining the Capital Accounts of the Members under Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the amount of such adjustment to the Capital Accounts will be treated as an item of gain (if the adjustment increases the basis of the Asset) or loss (if the adjustment decreases such basis) and such gain or loss will be specially allocated among the Members in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m) as contemplated by Section 4.2 hereof.

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(i)     The allocations required by Section 5.2(a) through (h) are intended to comply with the requirements of Treasury Regulation Sections 1.704-1(b), 1.704-1(d)(4) and 1.704-2. It is the intent of the Members that, to the extent the Company can do so consistently with the Treasury Regulations, the net amount of the allocations under this Article V to each Member will be the net amount that would have been allocated to each Member if this Agreement did not contain Section 5.2(a) through (h).

(j)     Upon a transfer of a Company Asset that constitutes “capital gain property” within the meaning of Treasury Regulation Section 1.755-1(a)(1), then notwithstanding any other provision of this Section 5.2 or Section 10.2, any item of gain resulting from such transfer shall be allocated first to any Member that has a deficit in its Capital Account and thereafter as set forth in Sections 5.1(a), (b) and (c). For the avoidance of doubt, gain for purposes of this Section 5.2(j) shall not include any gain for which Sections 1245(a)(1) or 1250(a) of the Code would apply.

Section 5.3     Tax Allocations.

(a)     Except as otherwise provided in this Section 5.3, for federal, state and local income tax purposes each item of income, gain, deduction and loss of the Company will be allocated to the Members in the same manner as the correlative item computed for purposes of the Capital Accounts is allocated and credited or debited pursuant to Sections 5.1 and 5.2. Allocations pursuant to this Section 5.3 are solely for purposes of federal, state and local taxes and will not affect, or in any way be taken into account in computing, any Member’s Capital Account or share of income, gain, deduction or loss or items thereof or distributions pursuant to any provision of this Agreement.

(b)     In order to remove book/tax discrepancies attributable to an Asset contributed to the Company by a Member or with respect to which an adjustment to the Gross Asset Value was made pursuant to subsection (b) of the definition of “Gross Asset Value,” items of taxable income, gain, loss and deduction will be allocated solely for federal, state and local income tax purposes as follows:

(i)     Items of Company income, gain, loss and deduction with respect to any property contributed to the Company (including income, gain, loss and deduction determined with respect to the alternative minimum tax) will be allocated among the Members in accordance with Section 704(c) of the Code and the Treasury Regulations thereunder so as to take account of any variation between the adjusted basis of such property to the Company for federal income tax purposes and its initial Gross Asset Value. The Company will use the “remedial method” described in Treasury Regulation Section 1.704-3(d).

(ii)     In the event the Gross Asset Value of any Company Asset is adjusted pursuant to subsection (b) of the definition of “Gross Asset Value,” subsequent allocations of Company taxable income, gain, loss and deduction with respect to such Asset will take account of any variation between the adjusted basis of such Asset (including such adjusted basis for alternative minimum tax purposes) and its Gross Asset Value in the same manner as under Section 704(c) of the Code and the Treasury Regulations thereunder, and, if such property was originally contributed to the Company by a Member, will be allocated in accordance with subsection (i) above.

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(c)     If any portion of gain recognized from the disposition of an Asset by the Company represents the “recapture” of previously allocated deductions by virtue of the application of Section 1245 or 1250 of the Code (“Recapture Gain”), such Recapture Gain will be allocated, solely for income tax purposes in accordance with Treasury Regulation Sections 1.1245-1(e)(2) and (3) and 1.1250-1(f).

(d)     To the extent that an adjustment to the adjusted tax basis of any Asset of the Company is made pursuant to Section 743(b) of the Code as a result of a Transfer of a Membership Interest in the Company, any adjustment will affect the transferee only and will not affect the Capital Account of the transferring Member or the transferee. In such case, the transferee will be required to agree to provide to the Company (i) information about the allocation of any step-up or step-down in basis to the Assets of the Company and (ii) the depreciation or amortization method for any step-up in basis to the Assets of the Company.

Section 5.4     Other Allocation Rules.

(a)     If the respective Membership Interests or allocation ratios described in this Article V of the existing Members in the Company change or if a Membership Interest is Transferred in compliance with this Agreement to any other Person, then, for the Tax Year in which the change or Transfer occurs, all Company items resulting from the operations of the Company shall be allocated, as between the Members for the Tax Year in which the change occurs or between the transferring Member and the transferee, by taking into account their varying interests using the interim closing of the books method permitted by Treasury Regulations Section 1.706-1(c)(2)(ii), unless otherwise agreed in writing by all the Members.

(b)     The Members agree that excess Nonrecourse Liabilities of the Company allocated to the Members under Treasury Regulation Section 1.752-3(a)(3) will be allocated in accordance with the sharing percentages set forth in Section 5.1(c). The allocations required by this subsection (b) are intended to comply with the requirements of Treasury Regulation Section 1.752-3(a)(3) and Revenue Ruling 95-41.

(c)     To the extent permitted by Treasury Regulation Section 1.704-2(h)(3) and 1.704-2(i)(6), the Members will endeavor to treat distributions of Distributable Cash as having been made from the proceeds of a Nonrecourse Liability or a Member Nonrecourse Debt only to the extent such distribution would cause or increase a deficit in the Adjusted Capital Account for any member.

(d)     Unless otherwise required by applicable law, the Company shall not treat any portion of the Existing Indebtedness as “recourse” debt for purposes of Section 752 of the Code or Treasury Regulation Section 1.704-2 as a result of the obligation of any Member to make contributions of cash to the Company under Article IV of this Agreement.

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(e)     For the avoidance of doubt, income and interest accrued on the Existing Indebtedness prior to the Closing Date and cash from the operation of the Projects prior to the Closing Date (including cash trapped in any reserve account) shall be for the sole account of the Class A Member and shall not be subject to the allocation provisions set forth in this Article V or the distribution provisions set forth in Article VI.

ARTICLE VI
DISTRIBUTIONS

Section 6.1     Distributions.

(a)     Except as provided otherwise in this Section 6.1, Section 4.3, Section 4.6, Section 4.7 or Section 10.2, Distributable Cash will be distributed to the Members as follows:

(i)     for periods prior to the Target Flip Date, two and one-half percent (2.5%) percent to the Class B Member and ninety-seven and one-half percent (97.5%) to the Class A Member;

(ii)     after the Target Flip Date (if the Flip Date has not yet occurred) until the Flip Date, one hundred percent (100%) to the Class B Member; and

(iii)     from and after the Flip Date, two and one-half percent (2.5%) to the Class B Member and ninety-seven and one-half percent (97.5%) to the Class A Member;

provided, however, in the event a Material Adverse Change in Tax Law occurs, the applicable Distributable Cash sharing ratios set forth in this Section 6.1(a) shall be adjusted to the extent necessary (with up to one hundred percent (100%) of Distributable Cash distributed to the Class B Member) to cause the Flip Date to occur as close to, and if possible on, the date that is two years from the Flip Date projected in the Tracking Model immediately prior to the occurrence of such Material Adverse Change in Tax Law.

(b)     Notwithstanding anything herein to the contrary, but subject to Section 6.1(d), Distributable Cash shall be distributed on each Distribution Date zero percent (0%) to the Class B Member and one hundred percent (100%) to the Class A Member, in an amount equal to the Capital Contributions made by the Class B Member pursuant to Section 4.3.

(c)     Distributions of Distributable Cash pursuant to this Section 6.1 will be made by the Managing Member on each Distribution Date.

(d)     Notwithstanding anything herein to the contrary, without the consent of the Class B Member, no distributions shall be made to any Class A Member hereunder so long as (i) a payment default under any Senior Note shall have occurred and be continuing, (ii) the Managing Member reasonably expects that a payment default under any Senior Note will or is reasonably likely to occur on or prior to the next applicable Distribution Date, or (iii) the Company has not complied with its obligations (and such obligations have not been voluntarily satisfied by OrLeaf or its Affiliates) under Section 4.7; provided, however, that to the extent there is Distributable Cash in excess of such payment default under any Senior Note plus the amount of any debt service reserve requirement deficiency, the Managing Member shall make a distribution of such Distributable Cash.

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(e)     If a Class B Contribution Default has occurred and is continuing, any Distributable Cash required to be distributed to the Class B Member under this Agreement will instead be distributed to the Class A Member in an amount not to exceed the Class B Defaulted Contribution, and such cash shall reduce on a dollar for dollar basis the outstanding amount of the Class B Defaulted Contribution.

(f)     Notwithstanding any other provision of this Agreement, if on any Distribution Date within a Tax Year that begins on and after the Flip Date, (x) the sum of PTCs actually generated and allocated to the Class B Member and Distributable Cash distributed to the Class B Member, within that Tax Year is not at least equal to (y) (i) the Highest Marginal Rate multiplied by (ii) the excess of income and gain allocated to the Class B Member for such Tax Year (plus any gain recognized by the Class B Member under Code Section 731(a)) over the amount of any unused losses previously allocated to the Class B Member that were suspended under Code Section 704(d) that become usable by the Class B Member during the Tax Year, then a portion of the Distributable Cash otherwise distributable to the Class A Member equal to that shortfall shall instead be distributed to the Class B Member.

Section 6.2     Withholding Taxes. If the Company is required to withhold taxes with respect to any allocation or distribution of Distributable Cash to any Member pursuant to any applicable federal, state or local tax laws, the Company may, after first notifying the Member and permitting the Member, if legally permitted, to contest the applicability of such taxes, withhold such amounts and make such payments to taxing authorities as are necessary to ensure compliance with such tax laws. Any funds withheld by reason of this Section 6.2 shall nonetheless be deemed distributed to the Member in question for all purposes under this Agreement. If the Company did not withhold from actual distributions of Distributable Cash any amounts it was required to withhold, the Company may, at its option, (i) require the Member to which the withholding was credited to reimburse the Company for such withholding, or (ii) reduce any subsequent distributions of Distributable Cash by the amount of such withholding. This obligation of a Member to reimburse the Company for taxes that were required to be withheld shall continue after such Member Transfers its Membership Interests in the Company. Each Member agrees to furnish the Company with any representations and forms as shall reasonably be requested by the Company to assist it in determining the extent of, and in fulfilling, any withholding obligations it may have.

Section 6.3     Limitation upon Distributions. No distribution or deemed distribution of Distributable Cash shall be made: (a) if such distribution of Distributable Cash would violate any contract or agreement to which the Company is then a party or any Legal Requirement then applicable to the Company, (b) to the extent that the Managing Member determines, in accordance with the Prudent Operator Standard, that any amount otherwise distributable should be retained by the Company to pay, or to establish a reserve for the payment of, any liability or obligation of the Company or any Subject Company, whether liquidated, fixed, contingent or otherwise, or to hedge an existing investment, including funding reserve accounts for spare parts and operational and maintenance costs for the Projects, or (c) to the extent that the Managing Member, in accordance with the Prudent Operator Standard, determines that the Distributable Cash is insufficient to permit such distribution or deemed distribution.

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Section 6.4     No Return of Distributions. Any distribution of Distributable Cash or deemed distribution or property pursuant to this Agreement shall be treated as a compromise within the meaning of Section 18-502(b) of the Act and, to the fullest extent permitted by law, any Member receiving or deemed to receive the payment of any such money or distribution of any such property shall not be required to return any such money or property to any Person, the Company or any creditor of the Company. However, if any court of competent jurisdiction holds that, notwithstanding the provisions of this Agreement, any Member is obligated to return such money or property, such obligation shall be the obligation of such Member and not of the other Members. Without limiting the generality of the foregoing, a deficit Capital Account of a Member shall not be deemed to be a liability of such Member nor an Asset or property of the Company.

Section 6.5     Substitute Payments. If the Company or any Subject Company receives any payments designated as compensation for any lost electrical production (including, without limitation, PTCs associated with such lost electrical production and any gross up amounts related thereto) relating to the construction, development, maintenance, testing and/or operation of any of the Projects (including any payment or indemnity received pursuant to Section 12.1 or any power purchase agreement with respect to any curtailment thereunder but excluding any payment of liquidated damages), the Managing Member shall determine the characterization of such payment (i.e., as a payment for lost PTCs or a payment for lost revenues under a power purchase agreement) and shall distribute such payment to the Members as appropriate, it being understood and agreed by the Members that a payment characterized as a payment for lost PTCs shall be distributed to the Members in accordance with the ratios set forth in Section 5.1 and all items of income associated therewith shall be allocated to the Members in accordance with Section 5.1, and a payment characterized as a payment for lost revenues under a power purchase agreement shall be distributed to the Members in accordance with the ratios set forth in Section 6.1; provided that any such determination, and any amendments to this Agreement required to implement such determination, shall be subject to obtaining the consent of the Members.

ARTICLE VII
ACCOUNTING AND RECORDS

Section 7.1     Reports.

(a)     The Managing Member shall prepare and deliver (or cause to be prepared and delivered) to each Member on or before the 20^th day after the end of each month, a written report (each, an “Operations Report”), in the form attached hereto as Exhibit D and such other relevant operational information as may from time to time be reasonably requested by a majority (by voting power) of the Class B Members.

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(b)     The Managing Member shall prepare (or cause to be prepared), and shall submit to each Member, an annual capital and operating budget for each Subject Company no later than 30 calendar days prior to the start of each Fiscal Year (the “Annual Budget”). The Annual Budget for each Fiscal Year will become effective automatically for any Fiscal Year, (A) if the aggregate expense amount reflected in the Annual Budget for any Fiscal Year does not exceed by more than ten percent (10%) the budgeted expense amount reflected in the immediately preceding Annual Budget, or (B) 15 calendar days after the Annual Budget is sent to each Member as provided in this Section, unless within such period a Class B Member holding fifty percent (50%) or more of the outstanding Class B Membership Interests gives the Managing Member written notice stating in reasonable detail which items of the Annual Budget they question or object to and the reasons for such question or objection, in which case the Annual Budget shall become effective with respect to (x) those items that are not subject to question or objection as set forth in the Annual Budget as submitted to Members and (y) pending resolution of any question or objection, the amount of any item subject to a question or objection shall be deemed to be ten percent (10%) greater than the amount in the immediately preceding Annual Budget, or (C) upon approval by Super-Majority Vote with respect to any item subject to question or objection that is not otherwise resolved by the Members, or (D) otherwise, as provided in Section 13.11. Upon approval of a Super-Majority Vote, the Managing Member may request that any budgeted amount reflected in the Base Case Model for any Fiscal Year be prospectively adjusted to give effect to any increases in costs or expenses that the Managing Member believes will affect budgeted amounts for more than one Fiscal Year.

(c)     The Managing Member shall prepare and deliver (or cause to be prepared and delivered) to each Member on or before the 30^th day after the end of each month a report setting forth the calculation of distributions of Distributable Cash for such month determined in accordance with Article VI hereof (the “Distribution Report”) in the form attached hereto as Exhibit E and such other relevant operational information as may from time to time be reasonably requested by a Class B Member holding twenty-five percent (25%) or more of the outstanding Class B Membership Interests.

(d)     The Managing Member shall calculate (or cause to be calculated) at least annually whether the Class B Members have reached the Target Internal Rate of Return, and shall send the Class B Members, within 120 days after the end of each Fiscal Year in which the Target Internal Rate of Return was not achieved, a report showing where it believes the Class B Members are in relation to the Target Internal Rate of Return (the “Target IRR Report”).

(e)     The Managing Member shall notify (or cause to be notified) the Class B Members in writing at least ten days before the Distribution Date following the month in which it believes the Class B Members achieved the Target Internal Rate of Return or at least 30 days before making any liquidating distributions, in connection with a liquidation of the Company pursuant to Section 10.1, if it believes the Class B Members will achieve the Internal Rate of Return as a consequence of the liquidating distributions (the “Target IRR Notice”). The Target IRR Notice will include the Managing Member’s Internal Rate of Return calculations and, in the case of a notice delivered in connection with a liquidation, the allocations and distributions that the Managing Member proposes to make to the Class B Members under Section 10.2 in light of the calculations.

(f)     On or before the 15^th day following each Fiscal Year, the Managing Member shall deliver (or cause to be delivered) to the Members a written report (each a “Production Report”), in the form attached hereto as Exhibit G, setting forth a calculation of the PTCs generated by the Projects and allocated to the Class B Members for such preceding Fiscal Year. The Production Report shall also set forth (i) Production eligible for PTCs during the Deferred Contribution Period, (ii) the projected allocation of gross income related to such Production to the Class B Member for such Deferred Contribution Period, (iii) the estimated Excess Production and (iv) the amounts owing by each Class B Member pursuant to Section 4.3(a) in respect of such Excess Production.

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(g)     Annually, together with the delivery of the proposed Tax Return to the Class B Members in accordance with Section 7.6, a written report setting forth the following:

(i)     The aggregate total of Excess Production generated by the PTC Eligible Projects;

(ii)     The aggregate total of Excess Production allocated to each of the Class B Members, as reflected on the Schedules K and K-1 of the Tax Returns filed by the Company, including such proposed Tax Return (or equivalent reporting under successor forms and procedures), as such Tax Returns shall have been amended or adjusted, and as such aggregate total shall have been adjusted based on a redetermination of the Flip Date in accordance with Section 13.11, or as a result of any tax audit, investigation, claim or controversy involving the Company that is the subject of Section 7.7;

(iii)     The aggregate amount that would be payable by each Class B Member under Section 4.3(a) based on the amount described in clause (i) above taking into consideration any extension of the due date for such amount pursuant to Section 4.3(b).

(iv)     The aggregate total actually contributed by each Class B Member pursuant to Section 4.3(a) and Section 4.3(b);

(v)     Any excess of the amount described in clause (iii) over the amount described in clause (iv) (an “Underpayment”); and

(vi)     Any excess of the amount described in clause (iv) over the amount described in clause (iii) (an “Overpayment”).

(h)     If a Class B Member holding twenty-five percent (25%) or more of the outstanding Class B Membership Interests disputes (in good faith) the calculation of any items in a Production Report, then such Class B Member shall notify the Managing Member not more than 30 Business Days after such Class B Member has received the applicable Production Report from the Managing Member.

(i)     In such event, such Class B Member and the Managing Member shall consider the issues raised or in dispute and discuss such issues with each other and attempt to reach a mutually satisfactory agreement. If notice of dispute is not given by such Class B Member within such period, each Production Report will be final and binding on the Members.

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(ii)     If the dispute as to the calculations is not promptly resolved within ten Business Days of such notification of the dispute, such Class B Member and the Managing Member shall each promptly present their interpretations to the Independent Accounting Firm, and shall instruct the Independent Accounting Firm to determine the correct amount of the calculations in dispute and to resolve the dispute promptly. The Independent Accounting Firm will make a determination as to each of the items in dispute, which must be (i) in writing, (ii) furnished to each Member and made in accordance with this Agreement, and which determination, absent manifest error, will be conclusive and binding on all Members. Each Member shall use reasonable efforts to cause the Independent Accounting Firm to render its decision as soon as reasonably practicable, including by promptly complying with all reasonable requests by the Independent Accounting Firm for information, books, records and similar items.

(iii)     In the event the Independent Accounting Firm determines that any of the calculations in dispute were incorrect in any material respect, the fees and expenses of the Independent Accounting Firm shall be borne by the Class A Member. In all other cases, the fees and expenses of the Independent Accounting Firm up to five hundred thousand dollars ($500,000), in the aggregate, shall be borne by the Company, and thereafter shall be borne by such Class B Member.

(iv)     The Class B Members will contribute to the Company the full amount then due and owing, if any, within five Business Days following (x) the receipt of the written determination of the Independent Accounting Firm or (y) reaching a mutually satisfactory agreement under clause (i), above.

(i)     Except as otherwise required under Section 8.3, the Managing Member shall provide (or cause to be provided) (i) all reports, notices, or other written communication relating to any dispute, potential default or event of default in connection with the Senior Notes, (ii) any Officer’s Certificate and Request for Withdrawal delivered by the Subject Companies (other than ORNI 37) to the Administrative Agent (under and as defined in the OFC2 Note Purchase Agreement) pursuant to Section 10.5 of the OFC2 Note Purchase Agreement and (iii) any other required report or formal, written notice received or delivered by the Company, or any of its subsidiaries, from or, as applicable, to the trustee under any Loan Document (as defined in the OFC2 Note Purchase Agreement), in each case, to the Class B Member within five Business Days of receipt or delivery of such reports, notices, or other written communication.

Section 7.2     Books and Records and Inspection.

(a)     The Managing Member shall cause the Company to keep and maintain (or to be kept and maintained on behalf of the Company), full and accurate books of account, financial records and supporting documents, which shall reflect, completely, accurately and in reasonable detail in all material respects each transaction of the Company and such other matters as are usually entered into the records or maintained by Persons engaged in a business of like character or as are required by law, and all other documents and writings of the Company. The books of account, financial records, and supporting documents and the other documents and writings of the Company shall be kept and maintained at the principal office of the Company. The financial records and reports of the Company shall be kept in accordance with GAAP and kept on an accrual basis.

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(b)     In addition to and without limiting the generality of Section 7.2(a), the Managing Member shall cause the Company to keep and maintain (or to be kept and maintained on behalf of the Company) at the Company’s principal office:

(i)     true and full information regarding the status of the financial condition of the Company, including any financial statements for the three most recent years;

(ii)     promptly after becoming available, a copy of the Company’s federal, state, and local income Tax Returns for each year;

(iii)     minutes of the proceedings of the Members and the Managing Member;

(iv)     a current list of the name and last known business, residence or mailing address of each Member and the Managing Member;

(v)     a copy of this Agreement and the Certificate of Formation, and all amendments thereto, together with executed copies of any written powers of attorney pursuant to which this Agreement and such Certificate of Formation and all amendments thereto and copies of written consents of Members;

(vi)     true and full information regarding the amount of cash and a description and statement of the agreed value of any other property and services contributed by each Member, and the date upon which each became a Member;

(vii)     copies of records that would enable a Member to determine the Member’s relative shares of the Company’s distributions and the Member’s relative voting rights; and

(viii)     all records related to the production and sale of electricity by the Subject Companies bearing on the qualification of such sales for PTCs.

(c)     Upon at least five Business Days prior notice to the Managing Member, all books and records of the Company shall be open to inspection and copying by any of the Members or their Representatives during business hours and at such Member’s expense, for any purpose reasonably related to such Member’s interest in the Company, provided that any such inspection or copying is conducted in a manner which does not unreasonably interfere with the Company’s business.

Section 7.3     Bank Accounts, Notes and Drafts.

(a)     All funds not required for the immediate needs of the Company may be placed in Permitted Investments, which investments shall have a maturity appropriate for the anticipated cash flows needs of the Company. All Company funds shall be deposited and held in accounts which are separate from all other accounts maintained by the Members and the Managing Member, and the Company’s funds shall not be commingled with any other funds of any other Person, including the Managing Member, any Member or any of their Affiliates (other than the Company itself).

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(b)     The Members acknowledge that the Managing Member may maintain Company funds in accounts, money market funds, certificates of deposit, other liquid Assets in excess of the insurance provided by the Federal Deposit Insurance Corporation, or other depository insurance institutions and that the Managing Member shall not be accountable or liable for any loss of such funds resulting from failure or insolvency of the depository institution, so long as any such maintenance of funds is in compliance with the first sentence of Section 7.3(a).

(c)     Checks, notes, drafts and other orders for the payment of money shall be signed by such Persons as the Managing Member from time to time may authorize. When the Managing Member so authorizes, the signature of any such Person may be a facsimile.

Section 7.4     Financial Statements.

(a)     As soon as practical after the end of each Quarter, but in any event within 60 calendar days after the end of each Quarter (excluding the Quarter ending December 31 of each year), the Managing Member shall furnish (or cause to be furnished) to each Member unaudited consolidated financial statements with respect to such Quarter for the Company consisting of (i) a balance sheet showing the Company’s financial position as of the end of such Quarter, (ii) profit and loss statements for the Company for such Quarter, and (iii) a statement of cash flows for the Company for such Quarter.

(b)     As soon as practical after the end of each Fiscal Year, but in any event within 120 calendar days after the end of the Fiscal Year, the Managing Member shall furnish (or cause to be furnished) each Member consolidated financial statements with respect to such Fiscal Year for the Company that are audited and certified by the Accounting Firm as presenting fairly in all material respects the financial conditions and results of operations of ORNI 37 LLC and OFC 2 LLC in accordance with GAAP consistently applied, subject only to normal year-end audit adjustments, consisting of (i) a balance sheet showing the Company’s financial position as of the end of such Fiscal Year, (ii) profit and loss statements for the Company for such Fiscal Year, (iii) a statement of cash flows for the Company for such Fiscal Year and (iv) related footnotes.

Section 7.5     Partnership Status and Tax Elections.

(a)     The Members intend that the Company will be taxed as a partnership for United States federal, state and local income tax purposes. The Members agree not to elect to be excluded from the application of Subchapter K of Chapter 1 of Subtitle A of the Code or any similar state statute and agree not to elect for the Company to be treated as a corporation, or an association taxable as a corporation, under the Code or any similar state statute.

(b)     The Company shall make the following elections on the appropriate Tax Returns:

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(i)     to the extent permitted under Section 706 of the Code, to adopt as the Company’s Tax Year the 12 month period ending on December 31 effective as of December 31, 2016;

(ii)     to adopt the accrual method of accounting;

(iii)     an election under Section 754 of the Code to adjust the bases of the Company’s properties;

(iv)     to elect to amortize the organizational expenses of the Company ratably over a period of 180 months as permitted by Section 709(b) of the Code;

(v)     [reserved]

(vi)     to elect under Section 59(e) of the Code to amortize intangible drilling and development costs over 60 months; and

(vii)     the Company and each Subject Company shall elect not to claim bonus depreciation on any Project pursuant to Section 168(k)(7) of the Code (or the equivalent successor provision).

The Managing Member shall make no other tax elections for the Company, except as specifically provided in this Agreement, without the approval in writing by Members representing a Super-Majority Vote, such approval not to be unreasonably withheld, provided, however, that the Managing Member may elect to extend the time for filing any tax returns required to be filed by the Company or any Subsidiary Company without the prior approval of any other Member.

(c)     The Company shall file an election under Section 6231(a)(1)(B)(ii) of the Code and the Treasury Regulation thereunder to treat the Company as a partnership to which the provisions of Sections 6221 through 6234 of the Code, inclusive, apply.

Section 7.6     Company Tax Returns.

(a)     Preparation of Tax Returns. The Tax Matters Partner shall prepare, or cause to be prepared by the Accounting Firm, and timely file (on behalf of the Company) all federal, state and local tax returns required to be filed by the Company. Each Member shall furnish to the Tax Matters Partner all pertinent information in its possession relating to the Company’s operations that is reasonably necessary to enable the Company’s tax returns to be timely prepared and filed.

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(b)     Preparation of Consistent Return. The Tax Matters Partner shall use good faith efforts to prepare, or cause to be prepared by the Accounting Firm, for each Tax Year, the Company’s federal income tax return, including Schedule K-1s (the “Tax Return”) in a manner that constitutes either a Consistent Return or an Excepted Non-Conforming Return. For purposes of this Agreement, a “Consistent Return” shall mean a Tax Return prepared on a basis consistent with the Fixed Tax Assumptions and other provisions in this Agreement and with Section 2.3 of the Contribution Agreement, and an “Excepted Non-Conforming Return” shall mean a Tax Return that is not prepared on a basis consistent with the Fixed Tax Assumptions and other provisions in this Agreement because there is not at least “substantial authority” (within the meaning of Regulation Section 1.6662-4(d)(2)) for filing a Tax Return on a basis consistent with the Fixed Tax Assumptions and other provisions in this Agreement as the result of (A) a final determination in any federal income tax audit or administrative or judicial proceeding involving such Tax Return or a Tax Return for a prior period making an adjustment to any item affected by the Fixed Tax Assumptions or (B) a Change in Tax Law or any other enactment, promulgation or issuance, as applicable, subsequent to the Effective Date of any of the types of authorities described in Treasury Regulation Section 1.6662-4(d)(3), (C) the breach of any representations, warranties, or covenants by a Class A Member, the Managing Member (as long as it is, or is an Affiliate of, a Class A Member) or the Tax Matters Partner (or Partnership Representative, as applicable) (as long as it is, or is an Affiliate of, a Class A Member) under this Agreement or the Contribution Agreement, or (D) the result of the breach of the representations, warranties or covenants of a Class B Member in Sections 3.11 or 12.3 of this Agreement or of Section 2.3 or Section 4.8 of the Contribution Agreement. A Tax Return that is neither a Consistent Return nor an Excepted Non-Conforming Return shall be a “Non-Conforming Return”).The Tax Matters Partner shall prepare the Tax Returns substantially in accordance with the Base Case Model except to the extent that any position taken in such Tax Returns (x) is one that the Accounting Firm will not report without disclosure under Code Section 6694(a)(2)(B) or (y) is one that is inconsistent with the other provisions of this Agreement. A Tax Return that is not filed substantially in accordance with the Base Case Model will be treated as a Non-Conforming Return.

(c)     Furnishing Returns. The Tax Matters Partner shall use commercially reasonable efforts to furnish to the Members:

(i)     by no later than March 15^th of each year, a copy of the Company’s Tax Return in the form proposed to be filed for the immediately preceding Tax Year,

(ii)     by no later than March 15^th of each year, written notification if the Tax Matters Partner anticipates furnishing to the Members a Tax Return that is a Non-Conforming Return for the immediately preceding Tax Year, and

(iii)     within twenty (20) days after filing such federal and state income Tax Returns and information returns, a copy of the Company’s federal and state income Tax Returns and information returns as filed for each Tax Year, together with any additional tax-related information in the possession of the Company that such Member may reasonably and timely request in order to properly prepare its own income Tax Returns.

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(d)     Consistent Return. Any proposed Tax Return delivered to the Members pursuant to Section 7.6(c)(i) as to which the Tax Matters Partner has given notice as described in Section 7.6(c)(ii) will be deemed to constitute a Tax Return that is a Non-Conforming Return for purposes of this Agreement. Any other proposed Tax Return delivered to the Members pursuant to Section 7.6(c)(i) will be deemed to constitute a Consistent Return or an Excepted Non-Conforming Return for purposes of this Agreement unless, within thirty (30) days of receipt of the proposed Tax Return pursuant to Section 7.6(c)(i), a Class B Member provides written notice to the Tax Matters Partner and the Managing Member that it disagrees that the proposed Tax Return is a Consistent Return or Excepted Non-Conforming Return, in which event, such dispute will be resolved in accordance with Section 13.11. If the Independent Accounting Firm determines pursuant to Section 13.11 that the proposed Tax Return does constitute either a Consistent Return or an Excepted Non-Conforming Return, then such Tax Return shall be deemed to constitute a Consistent Return or Excepted Non-Conforming Return for purposes of this Agreement. If the Independent Accounting Firm determines pursuant to Section 13.11 that the proposed Tax Return does not constitute either a Consistent Return or an Excepted Non-Conforming Return, then such proposed Tax Return shall be deemed as a Non-Conforming Return for purposes of this Agreement; provided, however, that, if the Tax Return actually filed by the Tax Matters Partner and the Accounting Firm (or any replacement Accounting Firm) constitutes a Consistent Return or an Excepted Non-Conforming Return in accordance with the Independent Accounting Firm’s determination pursuant to Section 13.11, then such Tax Return as so filed shall be deemed a Consistent Return or an Excepted Non-Conforming Return for purposes of this Agreement.

(e)     Costs of Preparation. The Company shall bear the costs of the preparation and filing of its returns, including the fees of Accounting Firm.

Section 7.7     Tax Audits.

(a)     OrLeaf is hereby designated as the “tax matters partner,” as that term is defined in Section 6231(a)(7) of the Code (the “Tax Matters Partner”), of the Company, with all of the rights, duties and powers provided for in Sections 6221 through 6234 of the Code, inclusive. The Tax Matters Partner is hereby directed and authorized to take whatever steps the Tax Matters Partner, in its reasonable discretion, deems necessary or desirable to perfect such designation, including filing any forms or documents with the IRS, taking such other action as may from time to time be required under the Treasury Regulations and directing the Managing Member to take any of the foregoing actions. The Tax Matters Partner shall remain as the Tax Matters Partner so long as it retains any ownership interests in the Company unless the Tax Matters Partner requests that it not serve as Tax Matters Partner and such request is approved by a Super-Majority Vote of the Members.

(b)     The Tax Matters Partner, in Consultation with the other Members, shall direct, or cause the Managing Member to direct, the defense of any claims made by the IRS to the extent that such claims relate to the adjustment of Company items at the Company level and, in connection therewith, shall cause the Company to retain and to pay the fees and expenses of counsel and other advisors chosen by the Tax Matters Partner in Consultation with the other Members. The Tax Matters Partner shall promptly deliver, or shall cause the Managing Member to promptly deliver, to each Member a copy of all notices, communications, reports and writings received from the IRS relating to or potentially resulting in an adjustment of Company items, shall promptly advise, or cause the Managing Member to promptly advise, each Member of the substance of any conversations with the IRS in connection therewith and shall keep, or cause the Managing Member to keep, the Members advised of all developments with respect to any proposed adjustments which come to its or the Managing Member’s, as the case may be, attention. In addition, the Tax Matters Partner shall or shall cause the Managing Member to (i) provide each Member with a draft copy of any correspondence or filing to be submitted by the Company in connection with any administrative or judicial proceedings relating to the determination of Company items at the Company level reasonably in advance of such submission, (ii) incorporate all reasonable changes or comments to such correspondence or filing requested by any Member and (iii) provide each Member with a final copy of correspondence or filing. The Tax Matters Partner will provide, or cause the Managing Member to provide, each Member with notice reasonably in advance of any meetings or conferences with respect to any administrative or judicial proceedings relating to the determination of Company items at the Company level (including any meetings or conferences with counsel or advisors to the Company with respect to such proceedings) and each Member shall have the right to participate, at its sole cost and expense, in any such meetings or conferences.

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(c)     For any issue or matter relating to the period prior to the Flip Date without the approval of Members collectively holding at least eighty percent (80%) of the Class B Membership Interests, the Tax Matters Partner shall not (i) commence a judicial action (including filing a petition as contemplated in Section 6226(a) or Section 6228 of the Code) with respect to a federal income tax matter or appeal any adverse determination of a judicial tribunal; (ii) enter into a settlement agreement with the IRS which purports to bind the Members; (iii) intervene in any action as contemplated by Section 6226(b) of the Code; (iv) file any request contemplated in Section 6227(b) of the Code; or (v) enter into an agreement extending the period of limitations as contemplated in Section 6229(b)(1)(B) of Code. Any cost or expense incurred by the Tax Matters Partner in connection with its duties as Tax Matters Partner shall be paid by the Company.

(d)     If for any reason the IRS disregards the election made by the Company pursuant to Section 7.5(c) and commences any audit or proceeding in which it makes a claim, or proposes to make a claim, against any Member that could reasonably be expected to result in the disallowance or adjustment of any items of income, gain, loss, deduction or credit (including PTCs) allocated to such Member by the Company, then such Member shall promptly advise the other Members of the same, and such Member, in Consultation with the other Members, shall use commercially reasonable efforts to convert the portion of such audit or proceeding that relates to such items into a Company level proceeding consistent with the Company’s election pursuant to Section 7.5(c).

(e)     If any Member intends to file, pursuant to Section 6227 of the Code, a request for an administrative adjustment of any such partnership item of the Company, or to file a petition under Sections 6226, 6228 or other Sections of the Code with respect to any such partnership item or any other tax matter involving the Company, such Member shall, at least 30 days prior to any such filing, notify the other Members of such intent, which notification must include a reasonable description of the contemplated action and the reasons for such action; provided, however, that this Section 7.7(e) shall not relieve such Member’s obligation to use all commercially reasonable efforts to convert a Member level proceeding into a Company level proceeding as provided in Section 7.7(d).

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(f)     Notwithstanding anything in this Agreement to the contrary, the Members agree to work together, reasonably and in good faith, to amend this Agreement for Tax Years for which the partnership audit provisions of Title XI are effective on or before the effective date of such provisions to the extent reasonably possible, to preserve and maintain (including through relevant elections and credit support) the relative and analogous rights, duties, responsibilities, indemnities, obligations and risks of the Members, including with respect to the payment of tax liabilities to those provided under this Agreement. In the event that subsequent to such amendment, there are further statutory amendments, Treasury Regulations, notices, revenue procedures, revenue rulings or other administrative guidance, interpreting or applying Title XI, the Members shall further amend this Agreement consistent with this Section 7.7(f). Notwithstanding the foregoing, in the event the Members have not amended this Agreement to the reasonable satisfaction of each Member on or before the effective date of Title XI (or any further guidance) then (i) OrLeaf, so long as it continues to retain an ownership interest in the Company, shall be designated the Partnership Representative, subject to removal and replacement rights analogous to those set forth in Section 7.7(a), (ii) for any notice of final partnership adjustment with respect to which an “imputed underpayment” within the meaning of Section 6225(b) of Title XI may be determined, the Company shall elect application of Section 6226 of Title XI and timely furnish to each Member of the Company for the reviewed year and to the U.S. Department of the Treasury a statement of each Member’s share of any adjustment to income, gain, loss, deduction, or credit, which shares will be calculated in a manner that takes into account the allocation of tax risk between the Members reflected in this Agreement; provided, such election shall not be made if, under subsequent guidance from the IRS, such election would transfer the audit or contest to the partner-level; provided, further, if, under subsequent guidance, the parties cannot make such election without transferring the audit or contest to the partner-level, then the Members agree to negotiate in good faith to amend this Agreement to retain the audit or contest at the Company level, while preserving the relative rights, burdens and economics of the Members, including each Member’s obligation to pay its respective share of the “imputed underpayment”, and (iii) the Partnership Representative shall not take any action that the Tax Matters Partner was not permitted to take without the consent of the Class B Member under Section 7.7(b) without the consent of the Class B Member. In the event a Section 6226 election cannot be made under the circumstances described in (ii) because of subsequent guidance from the IRS that would transfer the audit or contest to the partner level, each Member will be required to make a Capital Contribution to the Company as described in Section 4.5 within ten (10) Business Days of notice from the IRS that payment of the imputed underpayment is due and payable by the Company and such payment is not subject to appeal by the Company that would allow further deferral of such payment.

Section 7.8     Cooperation. Subject to the provisions of this Article VIII, each Member shall provide the other Members with such assistance as may reasonably be requested by such other Members in connection with the preparation of any Tax Return, any audit or other examination by any taxing authority, or any judicial or administrative proceedings relating to the liability for any Taxes with respect to the operations of the Company and the Subject Companies or the allowance or disallowance of any PTCs arising from the sale by the Subject Companies of electricity produced in their respective Projects.

Section 7.9     Fiscal Year. The Fiscal Year of the Company for financial reporting purposes will be a 12-month year ending December 31.

Section 7.10     Tax Year. The Tax Year of the Company will be a 12-month year ending December 31 unless the Company is required by Section 706 of the Code to use a different Tax Year.

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Section 7.11     Target Internal Rate of Return Determination.

(a)     Annual Determinations. Prior to the Flip Date, the Managing Member will (i) calculate (or will cause to be calculated) using the Tracking Model at least annually whether the Class B Member has reached the Target Internal Rate of Return and (ii) send the Class B Member, within 45 days after the end of each year in which the Target Internal Rate of Return was not achieved, a report in the form of the Target IRR Report showing where it believes the Class B Member is in relation to the Target Internal Rate of Return. The Managing Member will make its advisers available to answer any questions regarding the calculations contained in any such Target IRR Report.

(b)     Occurrence of Flip Date. If the Managing Member determines, in the manner provided in this Section 7.11, that the Flip Date has occurred, the Managing Member will notify the Class B Member in writing at least ten days before the Distribution Date following the month in which it believes the Class B Member achieved the Target Internal Rate of Return or at least 30 days before making any liquidating distributions, in connection with a liquidation of the Company pursuant to Section 10.2, if it believes the Class B Member will achieve the Target Internal Rate of Return as a consequence of the liquidating distributions. The notice will include the Target IRR Report showing the Managing Member’s calculations and, in the case of a notice delivered in connection with a liquidation, the allocations and distributions that the Managing Member proposes to make to the Class B Member under Section 10.2 in light of the calculations. The Managing Member will make its advisers available to answer any questions about the calculations contained in any such Target IRR Report.

(c)     Calculation Rules and Conventions. The Managing Member will employ the following calculation rules and conventions in determining whether the Class B Member has reached the Target Internal Rate of Return:

(i)     Continuity of Ownership. The Managing Member will treat ownership of the Class B Membership Interests as being continuous from the Closing Date to the relevant testing date as of which the calculation is being made without regard to any change in ownership of the Class B Membership Interests during such period.

(ii)     Cash Flows. The “Cash Flows” taken into account in determining the Internal Rate of Return will consist solely of (A) the Capital Contributions made by the Class B Member for the Class B Membership Interests on the Closing Date and the Deferred Contributions made pursuant to Section 4.3 (which for the avoidance of doubt includes any Deferred Contributions attributable to Excess Production prior to the Flip Date but payable after the Flip Date), (B) out-of-pocket costs and expenses paid or incurred by the Class B Member in connection with any event that is the subject of a Direct Claim that the Class A Member is required to pay, including amounts relating to the enforcement of such Direct Claim or the defense of any Third Party Claim against the Class B Member, (C) distributions to the Class B Member made on any (1) Distribution Date pursuant to Section 6.1, Section 4.3(c), or Section 4.7 or (2) date of distribution of liquidation proceeds pursuant to Section 10.2(b)(v) (or to be made on the Distribution Date or date of distribution of liquidation proceeds as of which the Internal Rate of Return is being determined), (D) subject to the proviso contained in the last sentence hereof, indemnity payments and cost and expense reimbursements received by a Class B Member from the Company or the Class A Member to compensate for the loss of amounts described in clauses (C) and (E) of this Section 7.11(c)(ii), but excluding any indemnity payments treated as cash distributions, and (E) the Grossed-Up PTC Amount based on the PTCs received by the Class B Member determined in accordance with subsection (iii) of this Section 7.11(c) to be received on any Estimated Tax Payment Date. Any amount received by the Class B Member which is in the nature of a recovery or replacement of, or indemnity or compensation for, and is the substantial economic equivalent of an item which would otherwise be taken into account in the foregoing clauses (A) through (E) will be deemed received for purposes of the calculation of the Internal Rate of Return on the date so received by such Class B Member; provided, however, that, any payments received pursuant to Article XI for lost depreciation deductions, other deductions and losses and credits other than PTCs shall not be taken into account for purposes of calculating the Internal Rate of Return in accordance with this Section 7.11(c)(ii).

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(iii)     PTCs.

(A)     PTC Amounts that are not consistent with the Fixed Tax Assumptions shall be recalculated for purposes of the Internal Rate of Return in a manner consistent with the Fixed Tax Assumptions, except to the extent that such inconsistency with the Fixed Tax Assumptions is the result of (1) the relevant Tax Return filed with the IRS by or for the Company being a Non-Conforming Return (as provided in Section 7.6(c)), (2) a change in the Code or Treasury Regulations promulgated thereunder that affect Fixed Tax Assumptions, or (3) the breach of any representations, warranties, or covenants by a Class A Member, the Managing Member, the Tax Matters Partner, or the Partnership Representative (in each case, as long as it is, or is an Affiliate of, a Class A Member) under this Agreement or the Contribution Agreement. PTC Amounts shall also be recalculated to include any credit that would have been realized by the Class B Member, but which is not so recognized as the result of the breach of the representations, warranties or covenants of a Class B Member in Sections 3.11 or 12.3(a) – (c) of this Agreement or of Sections 2.3 or 4.8 of the Contribution Agreement. For purposes of calculating and determining PTC Amounts, each Class B Member shall be treated as able to use immediately, subject to the same timing described in Section 7.11(c), and fully any PTC Amounts without regard to (X) whether the Class B Member has any income, gains, or tax liability against which it is permitted to offset such credits, (Y) any provision of Law limiting, restricting, deferring or disallowing such credit that is applicable to any Class B Member (as opposed to the Company), or (Z) a Company-level limitation, restriction, deferral or disallowance of such loss, deduction or credits that results from the breach of any representation, warranty or covenant of a Class B Member in this Agreement or the Contribution Agreement.

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(B)     For the avoidance of doubt, in all respects outside those described in Section 7.7(c)(iii) the Internal Rate of Return and the amount of Deferred Contributions shall be based upon the PTC Amounts or gross income allocation, as applicable, without any adjustment or recalculation, in accordance with the federal income tax accounting methods and tax elections actually used with respect to such period by the Company in the preparation of its Tax Returns, and as subsequently adjusted as a result of any amended Tax Return or a final determination in any federal income tax audit or subsequent administrative or judicial proceeding.

(C)     Estimated Tax Payment Dates. The distributive share of PTCs as determined for federal income tax purposes allocated by the Company to the Class B Member, shall be treated as recognized ratably during the Tax Year, with the result that the PTCs allocated to the Class B Members shall be treated as having been received in four equal installments on April 30, June 30, September 30, and December 31 during the Tax Year (the “Estimated Tax Payment Dates”), except that in the Tax Year in which the Flip Date occurs, such items allocated to the Class B Members for the period prior to the Flip Date will be treated as allocated ratably to each of the Estimated Tax Payment Dates during the Tax Year, and the present value, discounted at the Target Internal Rate of Return of items allocated to Estimated Tax Payment Dates after the Flip Date shall be taken into account for purposes of determining the Flip Date.

(d)     Method of Determining the Flip Date; Pro Ration of Distributions.

(i)     If, as of any Distribution Date after the Target Flip Date, the Managing Member calculates that the Flip Date has occurred during the calendar month in which such Distribution Date occurs (taking account of the distribution of the Distributable Cash on such Distribution Date and any Deferred Contributions due based on production prior to the Distribution Date but payable thereafter discounted to the Flip Date at the Target Internal Rate of Return) the Managing Member will calculate the lowest percentage (the “Trigger Percentage”) which, when applied to such Distributable Cash, will result in a Class B Unit receiving an amount of Distributable Cash (such amount of cash calculated using such Trigger Percentage, the “Cash Trigger Amount”) which will cause the Flip Date to occur. The Cash Trigger Amount shall be deemed to precede the Flip Date and shall be distributed to the Class B Members (notwithstanding anything to the contrary contained in Section 4.7 or Section 6.1(a)) and the remainder of such Distributable Cash shall be distributed to the Holders of Class A Units and Class B Units under Section 6.1(a)(iii).

(ii)     If, prior to a distribution of liquidation proceeds, the Managing Member calculates that the Class B Member will achieve the Target Internal Rate of Return as a consequence of the liquidating distributions (taking into account the expected distribution of liquidation proceeds), the Managing Member will calculate, using an iterative process, the percentage of the liquidation proceeds which, if distributed in accordance with Section 10.2(b)(v), will cause the cash distributions to be made pursuant to Section 10.2(b)(v) on the date of distribution of liquidation proceeds, to the extent such distributions are attributable to pro rata allocations pursuant to Section 10.2(b)(iv)(A), to cause the Flip Date to occur. Such calculation shall be taken into account in making the allocations under Section 10.2(b)(iv) in such manner as to ensure that, to the greatest extent feasible, the balances in the Capital Accounts of the Members are expected to result in distributions pursuant to Section 10.2(b)(v) in accordance with the target liquidation distributions contemplated in Section 10.2(b)(iv)(A) and Section 10.2(b)(iv)(B).

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(e)     End-of-Year True Up.

(i)     If the Class B Member achieves the Target Internal Rate of Return after the Target Flip Date, then prior to filing the Tax Return for the Tax Year which includes the Flip Date, the Managing Member shall compare the PTC Amounts for the portion of the Tax Year through the calendar month in which such Flip Date was determined to have occurred, as taken into account in the calculation of such Flip Date, with the PTC Amounts for such period as determined using the amounts reflected in the Tax Return as proposed to be filed, other than to the extent of any difference in such calculation of the Flip Date and such amounts reflected in the Tax Returns as the result of the application of the provisions of Section 7.11(c) or the calculation assumptions and conventions in this Section 7.11. In the event of any difference (disregarding de minimis amounts) the Managing Member shall apply such adjustments ratably to the Estimated Tax Payment Dates for such Tax Year and shall re-calculate the Trigger Percentage based upon the amounts reflected in such return and shall (A) adjust the Flip Date accordingly (including by advancing or retarding the Flip Date to a prior or subsequent calendar month), and (B) determine the difference (the “Cash Difference”) between the actual cash distribution to the Class B Members on the Distribution Date occurring in the month in which such Flip Date was originally determined to have occurred (and any subsequent Distribution Dates, if relevant) and the cash distribution which would have been made on such Distribution Date(s) based on the recalculated Trigger Percentage (it being acknowledged that any difference between the PTC Amounts assumed to be allocable to the Class B Interests at the time such Flip Date was first determined and the amounts of such PTC Amounts reflected in the allocations pursuant to the Tax Return actually filed has been reflected in the final determination of such Flip Date under this paragraph (i)).

(ii)     Provisions similar to those provided in Section 7.11 shall apply for purposes of advance notification to the Class B Members of the adjusted Flip Date and Cash Difference calculations referred to in paragraph (i), above, and the right of the Class B Members to challenge.

(iii)     Upon becoming final pursuant to this Section 7.11(e), the Managing Member shall apply the adjusted Flip Date for all purposes of this Agreement. On the Distribution Date immediately following the calculation becoming final, the sharing percentages set forth in Section 5.1(c) and Section 6.1(a)(iii) shall be adjusted to the maximum extent necessary (subject to the limit that the aggregate sharing percentages for the Class B Members shall not be less than five percent (5%) and the aggregate sharing percentages for the Class A Members shall not be less than one percent (1%)) so as to correct the Cash Difference on a present value basis calculated at the Target Internal Rate of Return, which adjusted sharing percentages shall remain in effect until elimination of the Cash Difference.

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(f)     Curative Flip Allocations. If, after filing the Tax Return for the Tax Year in which the Flip Date was determined to have occurred, there is change in the distributive share of Company items reported for the period through such Flip Date for reasons other than as the result of the application of the provisions of Section 7.11(c) or the calculation assumptions and conventions in this Section 7.11, and the Company has not yet made liquidating distributions under Section 10.2, then the following curative allocations, distributions and payments will apply and be effected by the Parties (the “Curative Flip Allocation”). The Managing Member will promptly determine the shortfall between the Internal Rate of Return actually achieved through the last Distribution Date that the Company distributed Distributable Cash under Section 6.1(a)(i) or (ii), as applicable, and the Target Internal Rate of Return. The sharing percentages in Section 5.1(c) and Section 6.1(a)(iii) then will be adjusted for allocations and distributions to be made subsequent to those relating to such last Distribution Date to the maximum extent and for so long as is necessary to eliminate such shortfall between the Internal Rate of Return actually achieved through the last Distribution Date that the Company distributed Distributable Cash under Section 6.1(a)(i) or (ii), as applicable, and the Target Internal Rate of Return (subject to the limit that the aggregate sharing percentages for the Class B Members shall not be less than five percent (5%) and the aggregate sharing percentages for the Class A Members shall not be less than one percent (1%)). If an event occurs that would have triggered a Curative Flip Allocation but for the fact that a Class A Member has already purchased the Class B Interests pursuant to Section 9.6 or Section 9.7, then such Class A Member will pay in cash, within twenty (20) Business Days following the occurrence of such event, the economic equivalent of the Curative Flip Allocation as additional purchase price for the Class B Interests.

(g)     Disputes. Any dispute by the Class B Member of any item or procedure or calculation of, or which affects, the Target Internal Rate of Return contained in any notice or report delivered to the Class B Member will be disputed in accordance with the dispute resolution mechanism set forth in Section 13.11.

ARTICLE VIII
MANAGEMENT

Section 8.1     Managing Member.

(a)     The Managing Member shall be the Member designated to act as such hereunder from time to time in accordance with the provisions of this Section 8.1 (the “Managing Member”). The initial Managing Member shall be OrLeaf. Except (i) for Major Decisions and Fundamental Decisions, which shall be determined as set forth in Section 3.2, and (ii) as otherwise required by applicable Legal Requirements or as otherwise expressly provided in this Agreement (including Other Consent Matters), the Managing Member shall perform the services set forth in Schedule 8.1(a) and conduct, direct and exercise control over all activities of the Company, and shall have full power and authority on behalf of the Company to manage and administer the business and affairs of the Company and to do or cause to be done any and all acts reasonably considered by the Managing Member to be necessary or appropriate to conduct the business of the Company (including, without limitation, all necessary actions to cause each of the Subject Companies to perform its obligations and enforce its rights under the Material Contracts to which it is a party and to otherwise carry out its respective purposes) without the need for approval by or any other consent from any Member, including, but not limited to, the authority to bind the Company in making contracts and incurring obligations in the Company’s name in the course of the Company’s business.

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(b)     In carrying out its duties and obligations under this Agreement, the Managing Member shall be required to perform such duties and obligations in accordance with the material requirements of the Transaction Documents, Material Contracts and of the Licenses and Permits (as defined in the Contribution Agreement), applicable laws, the purposes set forth in Section 2.3 and in good faith and in a manner reasonably believed to be in the best interest of the Subject Companies and the Projects, in each case taking into account, for so long as PTCs are available to any PTC Eligible Projects, the requirements to maintain and generate PTCs.

(c)     The Managing Member may, at any time, upon not less than 60 Business Days’ notice to the other Members resign as Managing Member and will in good faith assist the Members with finding a replacement Managing Member and providing them with reasonable assistance in transitioning to the new Managing Member. The Class B Members holding eighty percent (80%) of the Class B Membership Interests may, at any time and from time to time, remove the Managing Member for Cause and fill any vacancy resulting therefrom. In addition, the Managing Member shall be removed automatically without further vote, action or notice by any Member in the event of a Bankruptcy of the Managing Member, the Tax Matters Partner or the Class A Member, unless those Members who are not Affiliates of the Managing Member elect otherwise upon written notice.

Section 8.2     Major Decisions.

(a)     In addition to any other approval required by applicable Legal Requirements or this Agreement, Major Decisions are reserved to the Members, and subject to Section 3.2, none of the Company, the Managing Member, or any officer, employee or agent thereof shall do or take or make or approve any Major Decisions prior to the later of (i) the Flip Date and (ii) the date upon which the Class B Member’s restoration obligations pursuant to Section 10.3(b) have been reduced to zero dollars ($0) without a Super-Majority Vote of Members.

(b)     The decision of each Member as to whether or not to consent to any Major Decision shall be in the sole discretion of such Member. A request for consent shall be sent by the Managing Member to each Member as provided in Section 13.1. A Member will be deemed to have consented if no written response is received from that Member within fourteen (14) Business Days of the confirmed delivery date of a request for consent sent to such Member. The Managing Member shall make reasonable efforts to confirm the actual delivery date to the Class B Member by seeking an email acknowledgement that such consent request was received and is under review; provided, however, that such fourteen (14) Business Days shall be extended for a reasonable period to the extent requested by the Class B Member, it being understood that reasonable requests for additional information by such Member shall be treated as a valid extension request extending through such time as the supplementary information is provided, and such Member is actively reviewing it and has had a reasonable amount of time to evaluate such information in light of the consent being requested.

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Section 8.3     Fundamental Decisions.

(a)     In addition to any other approval required by applicable Legal Requirements or this Agreement, Fundamental Decisions are reserved to the Members, and none of the Company, the Managing Member, or any officer, employee or agent thereof shall do or take or make or approve any Fundamental Decision without a Super-majority Vote.

(b)     The decision of each Member as to whether or not to consent to any Fundamental Decision shall be in the sole discretion of such Member. A request for consent shall be sent by the Managing Member to each Member as provided in Section 13.1. A Member will be deemed to have consented if no written response is received from that Member within fourteen (14) Business Days of the confirmed delivery date of a request for consent sent to such Member. The Managing Member shall make reasonable efforts to confirm the actual delivery date to the Class B Member by obtaining an email acknowledgement that such consent request was received and is under review; provided, however, that such fourteen (14) Business Days shall be extended for a reasonable period to the extent requested by the Class B Member, it being understood that reasonable requests for additional information by such Member shall be treated as a valid extension request extending through such time as the supplementary information is provided, and such Member is actively reviewing it and has had a reasonable amount of time to evaluate such information in light of the consent being requested.

Section 8.4     Insurance. The Managing Member shall cause the Company and its Subsidiaries to acquire and maintain (including making changes to coverage and carriers) the casualty, general liability (including product liability), property damage and/or other types of insurance set forth in Schedule 8.4; provided that, if any such insurance is not available on commercially reasonable terms (which shall be to the reasonable satisfaction of the Class B Member, provided that if the Class B Member does not provide a written response manifesting an unambiguous agreement or disagreement within ten Business Days of notification of such determination the Class B Member shall be deemed to be in agreement), the Managing Member shall cause the Company to establish reasonably satisfactory self-insurance reserves and replacement third party insurance shall be procured as soon as commercially reasonable terms are available. The Members shall be added to such insurance as named insured and loss payee as their interests may appear (except for any workers’ compensation policy), with a waiver of subrogation permitted in their favor (where legally permitted or insurance market practice permits). Unless the insurance required to be carried pursuant to Schedule 8.4 requires the insurer to provide the Members with at least 30 days written notice of cancellation (ten days for non-payment of premium), the Managing Member hereby covenants and agrees to give the Class B Members at least 30 days written notice of cancellation (ten days for non-payment of premium) to the extent that it receives such notice from the insurer.

Section 8.5     Notice of Material Breach. The Managing Member shall notify the Class B Members within five Business Days of obtaining actual knowledge of any (a) written notice of default delivered by a party to a Material Contract to a Subject Company or the Managing Member or (b) default by a party to a Material Contract (other than a Subject Company or any Affiliate thereof) under such Material Contract, in the case of either (a) or (b), which default, would be reasonably likely to result in a Material Adverse Effect; provided, however, that in the case of any notice of default in connection with the Senior Notes, the Managing Member shall be required to notify, and provide such notice to, the Class B Members immediately and in all cases not later than the following Business Day.

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Section 8.6     Anti-Corruption Laws and Sanctions. The Managing Member shall (a) cause the Company to maintain in effect and enforce policies and procedures designed to ensure compliance by the Company, and their respective directors, officers, employees and agents, with Anti-Corruption Laws and applicable Sanctions and otherwise to prevent interactions with Prohibited Persons and (b) require that third party counterparties implement and maintain similar procedures designed to ensure compliance by such counterparties with Anti-Corruption Laws and applicable Sanctions and otherwise to prevent interactions with Prohibited Persons. The Managing Member shall cause the Company, and its directors, officers, employees and agents (x) not to make, or take any action in furtherance of, any offer, payment, promise to pay, or authorization of the payment or giving of money, or anything else of value, to any Person in violation of any Anti-Corruption Laws and (y) not to use the Company funds (i) for the purpose of funding, financing or facilitating any activities, business or transaction of or with any Sanctioned Person or in any Sanctioned Country or (ii) in any manner that would result in the violation of any Sanctions.

ARTICLE IX
TRANSFERS

Section 9.1     Prohibited Transfers.

Except for Permitted Transfers, no Member shall sell, transfer, assign, convey, pledge, mortgage, encumber, hypothecate or otherwise dispose of all or any part of its Membership Interests or any interest, rights or obligations with respect thereto, directly or indirectly (including through a change of control or merger of such Member) (any such action, a “Transfer”), except as provided in this Article IX. Any attempted Transfer that does not comply with this Article IX shall be null and void and of no force or effect whatsoever.

Section 9.2     Conditions Applicable to All Transfers.

(a)     Except as otherwise provided in this Section 9.2, all Transfers of Membership Interests must satisfy the following conditions:

(i)     The transferring Member must give notice of the proposed Transfer to each of the other Members not less than ten (10) days prior to the effective date of the proposed Transfer.

(ii)     The transferring Member and the prospective transferee each execute, acknowledge and deliver to the Company such instruments of transfer and assignment with respect to such Transfer and such other instruments as are reasonably satisfactory in form and substance to the other Members to effect such Transfer and to confirm the transferor’s intention that the transferee become a Member in its place, and the prospective transferee makes the representations and warranties set forth in Section 3.11 as of the date of such Transfer.

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(iii)     The transferee executes, adopts and acknowledges this Agreement, and executes such other agreements as the Managing Member may reasonably deem necessary or appropriate to confirm the undertaking of the transferee to be bound by the terms of this Agreement and to assume the obligations of the transferor under this Agreement and the Contribution Agreement (to the extent the transferor is to be released from such obligations).

(iv)     The Transfer will not violate (x) any securities laws or any other applicable federal or state laws or the order of any court having jurisdiction over the Company or any of its Assets or (y) any material contract, lease, security, indenture or agreement binding on any Subject Company or its Assets.

(v)     In the case of a Transfer by the Class B Member, such Transfer will not result in a termination of the Company or any Subject Company under Section 708(b)(1)(B) of the Code unless the transferor has indemnified the other Members for any adverse tax consequences incurred as a result of such termination in an amount determined on a present value basis using the Target Internal Rate of Return as the discount rate and using the Tracking Model results to the date of such Transfer, but otherwise not changing any of the inputs and assumptions from the Base Case Model. In the case of a Transfer by the Class A Member, such Transfer will not result in a termination of the Company or any Subject Company under Section 708(b)(1)(B) of the Code unless the transferor has indemnified the other Members for any adverse tax consequences incurred as a result of such termination in an amount determined on a present value basis using the Tracking Model results to the date of such Transfer, but otherwise not changing any of the inputs and assumptions from the Base Case Model.

(vi)     The Transfer will not cause the Company to be classified as a publicly traded partnership treated as a corporation for federal income tax purposes or result in any of the Projects becoming tax-exempt use property, in whole or in part, within the meaning of Section 168(h) of the Code during any applicable recovery period.

(vii)     All consents, approvals and filings required to be obtained or made in connection with the Transfer will have been obtained or made and will be in full force and effect.

(viii)     The Transferee is an Unrelated Person.

(ix)     The Transferee is a “United States person” within the meaning of Section 7701(a)(30) of the Code.

(b)     If the Transfer involves Class A Membership Interests (including, for the avoidance of doubt, a Transfer upon foreclosure (or in lieu of such foreclosure) under an Encumbrance relating to such Class A Membership Interest), (i) through and including the Flip Date, the Transfer must be approved by a Super-Majority Vote of Members and (ii) the Transferee shall have provided such “Know Your Customer” information as shall be required by the policies and procedures of the Class B Member.

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Section 9.3     Conditions Applicable to All Transfers of Class B Membership Interests. Except as otherwise provided in this Section 9.3, all Transfers of Class B Membership Interests must satisfy the following conditions (in addition to those in Section 9.2):

(i)     An agreement (or agreements), in form and substance satisfactory to the Class A Member, shall be in full force and effect with respect to the transferee in which the transferee agrees to be bound by all the provisions of (x) this Agreement, including Sections 9.5 and 9.6 of this Agreement, and (y) the Contribution Agreement insofar as it relates to the Class B Membership Interests transferred, including Article VI thereof.

(ii)     Such Transfer will not result in any Person that is not an Approved Transferee holding a Class B Membership Interest.

Section 9.4     Certain Permitted Transfers.

(a)     Notwithstanding the foregoing provisions of this Article IX, except as otherwise provided in this Section 9.4, the following Transfers (the “Permitted Transfers”) may be made at any time and from time to time, without restriction and without notice to, approval of, filing with, consent by, or other action of or by, any Member or other Person:

(i)     The issuance of Membership Interests pursuant to the Contribution Agreement.

(ii)     The grant of any security interest in any Membership Interest pursuant to any security agreement any Member may enter into with lenders.

(iii)     A Transfer to a Class A Approved Transferee in connection with any foreclosure or other exercise of remedies in respect of any Class A Membership Interest subject to a security interest referred to in Section 9.4(a)(ii).

(iv)     Any Transfer of all or a portion of the stock, membership interests or Assets (including any change of control or merger) of OrLeaf or any upstream Affiliate of OrLeaf (other than the Assets of any such Affiliate that are Membership Interests); provided, that, prior to the Flip Date, in connection with such transfer Ormat Technologies Inc. will retain direct or indirect control of over fifty percent (50%) of the voting interest in Ormat and Ormat will remain the managing member of OrLeaf.

(v)     Any Transfer of Class B Membership Interests by any Class B Member or any Affiliate of such Class B Member to any other Class B Member or any Affiliate of such Class B Member.

(vi)     Any Transfer of Class B Membership Interests by any Class B Member or any Affiliate of such Class B Member in connection with Section 9.11.

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(vii)     Any Transfer of all or a portion of the stock, membership interests or Assets (including any change of control or merger) of the Class B Members or any Affiliates of the Class B Members (other than (x) the Assets of any such Affiliate that are Membership Interests and (y) the stock or membership interests of any such Affiliate the Assets of which consist primarily of Membership Interests, directly or indirectly, and such Transfer would result in either (1) any event referred to in Section 9.2(a)(v), (vi) or (ix) or (2) Membership Interests being held, directly or indirectly, by a Person that is a Competitor).

(viii)     Any Transfer made in accordance with Sections 9.5 or 9.6.

(b)     The conditions set forth in Section 9.2(a)(ii) through (vii) shall apply to the Permitted Transfers referred to in Section 9.4(a)(iii).

Section 9.5     Right of First Offer.

(a)     If at any time any Class B Member desires to Transfer any of its Class B Membership Interests to any third Person, other than an Affiliate of such Class B Member, prior to offering the Class B Membership Interests to any such third Person, such Class B Member shall first give notice to the Class A Member (the “Offer Notice”).

(b)     The Class A Member shall have the right, for a period of 30 calendar days after receipt of an Offer Notice, to inform the Class B Member in writing of its offer to purchase the subject Class B Membership Interests, including the price and other terms of such offer (such offer, the “ROFO Offer”). Any ROFO Offer, if given, shall be irrevocable.

(c)     If the Class B Member chooses, in its sole discretion, to accept the ROFO Offer the closing of the Transfer of the Class B Membership Interests covered by any ROFO Offer shall occur no later than 45 days after the ROFO Offer is given or such later date as may be required to obtain any applicable governmental consents or approvals, or to satisfy any reporting or waiting period under any applicable Legal Requirements, or at such other time as the parties agree.

(d)     If the ROFO Offer is exercised, at the closing of the Transfer, (1) the Class A Member shall pay (by wire transfer of immediately available United States Dollars to such United States bank accounts as the Class B Member may designate in a written notice to the Company and Class A Member no later than five Business Days prior to the closing date for the Transfer pursuant to the ROFO Offer) an amount equal to the product of (i) the cash price of the Class B Membership Interests set forth in the Offer Notice, multiplied by (ii) the Class B Membership Interests subject to the ROFO Offer Notice and (2) the Class B Member shall take the following actions: (i) the Class B Member shall Transfer to the Class A Member all right, title and interest in and to the Class B Membership Interests, free and clear of all Encumbrances other than Permitted Encumbrances; (ii) the Class B Member shall be deemed to have made the representations set forth on Schedule 9 attached hereto to the Class A Member and the Company; and (iii) the Class B Member shall take all such further actions and execute, acknowledge and deliver all such further documents that are necessary to effectuate the Transfer of the Class B Membership Interests contemplated by this Section. Upon the closing of such Transfer, (1) all of the Class B Member’s obligations and liabilities associated with the Class B Membership Interests which are the subject of such Transfer will terminate except those obligations and liabilities accrued through the date of such closing, (2) the Class B Member shall have no further rights as a Member in respect of the Class B Membership Interests which are the subject of such Transfer, and (3) all the rights, obligations and liabilities associated with the Class B Membership Interests which are the subject of such Transfer shall become the rights, obligations and liabilities of the Class A Member.

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(e)     If the Class B Member chooses not to accept the ROFO Offer the Class B Member may Transfer the Class B Membership Interests to any third Person, subject to the other restrictions contained herein.

(f)     A proposed Transfer between one Class B Member to another Class B Member, or between respective Affiliates of such Class B Members, shall not be subject to the right of first offer as set forth in this Section 9.5.

Section 9.6     Flip Purchase Option.

(a)     The Class A Member (or any Affiliate of the Class A Member designated by it) shall have the right to acquire all (but not less than all) of the Class B Membership Interests on either of (i) the Target Flip Date or (ii) the date that is 9.0 years after the Closing Date (the “Flip Purchase Option”), in either case upon providing written notice no later than 90 days prior to such date to the Company and the Class B Member of its election to exercise the Flip Purchase Option (the “Flip Exercise Notice”). Any Flip Exercise Notice, if given, shall be irrevocable; provided that, if the Class A Member defaults on its obligation to purchase the Class B Membership Interest pursuant hereto, the Flip Purchase Option shall expire.

(b)     The consideration for the Transfer of the Class B Membership Interests to the Class A Member pursuant to the Flip Purchase Option shall be an amount (payable in United States dollars) equal to the greater of (i) the Fair Market Value of the Class B Membership Interests as of the date of the purchase of the Class B Membership Interests pursuant to this Section 9.6, increased to account for any minimum gain chargeback after taking into account any suspended losses under Section 704(d) of the Code the Class B Member recognizes due to the exercise of the Flip Purchase Option assuming a tax rate equal to the Highest Marginal Rate, and (ii) $3,000,000; provided, that if the Class B Member has not yet achieved the Target Internal Rate of Return, the consideration for the Transfer of the Class B Membership Interests shall first consist of the amount necessary to cause the Class B Member to achieve its Target Internal Rate of Return and then the applicable amount set forth in subclause (i) or (ii) of this Section 9.6(b) (the “Flip Purchase Price”). The Fair Market Value of the Class B Membership Interests shall be determined by agreement between the Class A Member and the Class B Member. If they fail to agree upon such value within thirty (30) days after the date of the Buyout Notice, the Members shall, promptly thereafter, initiate the Appraisal Method for purposes of establishing such Fair Market Value.

(c)     If the Flip Purchase Option is exercised, the closing of such Transfer shall occur on the Business Day that is (i) 60 days after the applicable Flip Exercise Notice is given or (ii) such later date as may be required to obtain any applicable consents or approvals or satisfy any reporting or waiting period under any applicable Legal Requirements.

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(d)     If the Flip Purchase Option is exercised, at the closing of the Transfer, (1) the Class A Member shall pay (by wire transfer of immediately available United States Dollars to such United States bank accounts as the Class B Members may designate in a written notice to the Company and the Class A Member no later than five Business Days prior to the closing date for the Transfer pursuant to the Flip Purchase Option) an amount equal to the Flip Purchase Price (determined in accordance with Section 9.6(b)) and (2) the Class B Members shall take the following actions: (i) such Class B Member shall Transfer to the Class A Member, all right, title and interest in and to the Class B Membership Interests, free and clear of all Encumbrances other than Permitted Encumbrances; (ii) such Class B Member shall be deemed to have made the representations set forth on Schedule 9 attached hereto to each such Class A Member and the Company; and (iii) such Class B Member shall take all such further actions and execute, acknowledge and deliver all such further documents that are necessary to effectuate the Transfer of the Class B Membership Interests contemplated by this Section. Upon the closing of such Transfer, (x) all of such Class B Member’s obligations and liabilities associated with the Class B Membership Interests which are the subject of such Transfer will terminate except those obligations and liabilities accrued through the date of such closing, (y) such Class B Member shall cease to be a Member, and (z) all the rights, obligations and liabilities associated with the Class B Membership Interests which are the subject of such Transfer shall become the rights, obligations and liabilities of each Person acquiring such Class B Membership Interests.

Section 9.7     Buy-Out Event.

(a)     Following the occurrence of a Material Adverse Change in Tax Law for which the Distributable Cash ratios may be modified as provided in the proviso in Section 6.1(a), the Class A Member shall have the option to acquire all, but not less than all, of the Class B Membership Interest of the Class B Member in accordance with the requirements provided in Section 9.2. Such option may be exercised by the Class A Member by giving to the Class B Member written notice to such effect no later than sixty (60) Business Days after the occurrence of such Material Adverse Change in Tax Law (the “Buyout Notice”).

(b)     The purchase price for the Class B Membership Interests being purchased pursuant to this Section 9.7 shall be the greater of (i) the amount necessary to cause the Class B Member to achieve the 20-Year IRR Rate and (ii) the Fair Market Value of the Class B Membership Interests as of the date of such purchase.

(c)     Within twenty (20) days after the date of the Buyout Notice, the Members will meet to discuss and negotiate in good faith to determine and agree upon the Fair Market Value of the Class B Membership Interests. If they agree upon such Fair Market Value, such value will be deemed to be the Fair Market Value for purposes hereof. If they fail to agree upon such value within thirty (30) days after the date of the Buyout Notice, the Members shall, promptly thereafter, initiate the Appraisal Method for purposes of establishing such Fair Market Value.

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(d)     The closing of any such purchase shall occur on the later of the thirtieth (30^th) Business Day following the date of the Buyout Notice, the twentieth (20^th) Business Day following the determination of the Fair Market Value of the Class B Membership Interests, and the fifth (5^th) Business Day after the receipt of all applicable necessary approvals from any Governmental Body. At the closing, the Class B Member shall convey the Class B Membership Interests to the Class A Member on an “as is, where is” basis without representations or warranties, expressed or implied, other than that the Class B Member has good and marketable title to the Class B Membership Interests and that no encumbrance against the Class B Membership Interests then exists other than those created pursuant to this Agreement. At the closing, (1) the Class A Member shall expressly assume any and all obligations and liabilities of the Class B Member under this Agreement (except those obligations or liabilities accrued through the date of such closing), (2) the Class A Member shall amend this Agreement to reflect the withdrawal of the Class B Member and the redemption or transfer of the Class B Membership Interests effective as of the date of such closing, and (3) the Class A Member shall pay the purchase price to the Class B Member by wire transfer of immediately available funds.

Section 9.8     Regulatory and Other Authorizations and Consents. In connection with any Transfer pursuant to Sections 9.5, 9.6 or 9.7 (a “Designated Transfer”), each Member involved shall use all commercially reasonable efforts to obtain all authorizations, consents, orders and approvals of, give all notices to and make all filings with, all Governmental Bodies and third parties that may be or become necessary for the Designated Transfer, its execution and delivery of, and the performance of its obligations under, this Agreement or other Transaction Documents in connection with any such Designated Transfer and will cooperate fully with the other Members in promptly seeking to obtain all such authorizations, consents, orders and approvals, giving such notices and making such filings, including the provision to such third parties and Governmental Bodies of such financial statements and other publicly available financial information with respect to such Member, as such third parties or Governmental Bodies may reasonably request; provided, however, that no Member involved shall have any obligation to pay any consideration to obtain any such consents. In addition, the Members involved shall keep each other reasonably apprised of their efforts to obtain necessary consents and waivers from third parties or Governmental Bodies and the responses of such third parties and Governmental Bodies to requests to provide such consents and waivers.

Section 9.9     Admission. Any transferee of all or part of any Membership Interests pursuant to a Transfer made in accordance with this Agreement shall be admitted to the Company as a substitute Member upon its execution of a counterpart to this Agreement.

Section 9.10     Security Interest Consent. If any Member grants a security interest in any Membership Interest to a Class A Approved Transferee, upon request by such Member, each other Member will execute and deliver to such Class A Approved Transferee holding such security interest (for itself and/or for the benefit of other lenders) such acknowledgments, consents or other instruments as such Class A Approved Transferee may reasonably request to confirm that such grant and any foreclosure or other exercise of remedies in respect of such Membership constitutes a Permitted Transfer under this Agreement.

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Section 9.11     Regulatory Compliance.

(a)     In the event that the Class B Member reasonably determines that it has a Regulatory Problem, the Company and the Managing Member agree at the sole cost and expense of the Class B Member to take all such actions as are reasonably requested by such Class B Member in order (i) to effectuate and facilitate any transfer by such Class B Member of any securities in the Company then held by the Class B Member to any Person designated by such Class B Member; provided, that Section 9.3 shall be complied with, (ii) to permit such Class B Member (or any of its Affiliates) to exchange all or any portion of the voting securities then held by such Person on a share-for-share basis for shares of a class of non-voting securities of the Company, which non-voting securities shall be identical in all respects to such voting securities, except that such new securities shall be non-voting and shall be convertible on such terms as are requested by such Class B Member into voting securities and reasonably acceptable to the Company in light of regulatory considerations then prevailing, and (iii) to continue and preserve the respective allocation of the voting interests with respect to the Company arising out of such Class B Member’s ownership of voting securities before the transfers and amendments referred to above (including entering into such additional contracts as are reasonably requested by such Class B Member to permit any Person(s) designated by such Class B Member to exercise any voting power which is relinquished by such Class B Member upon any exchange of voting securities for nonvoting securities of the Company); and at the sole cost and expense of such Class B Member, the Company shall enter into such additional contracts, adopt such amendments to this Agreement and other relevant contracts and take such additional actions, in each case as are reasonably requested by such Class B Member in order to effectuate the intent of the foregoing; provided that any such additional contracts, amendments to this Agreement or other relevant contracts, or other actions shall not have an adverse impact on the Company or any other Member. If such Class B Member is, or elects to transfer securities of the Company in order to avoid a Regulatory Problem to, a Regulated Holder, the Company and each of the Members agree at the request of such Class B Member that the provisions of this Section 9.11 shall be applicable to such Regulated Holder in order to assist such Regulated Holder in complying with applicable laws and regulations to which it is subject. To the extent necessary to comply with such laws and regulations, such agreements may include restrictions on the redemption, repurchase or retirement of securities of the Company that would result or be reasonably expected to result in such Regulated Holder holding more voting securities or total securities (equity and debt) than it is permitted to hold under such laws and regulations.

(b)     In the event such Class B Member has the right to acquire any of the Company’s securities from the Company or any other Person (as the result of a preemptive offer, pro rata offer or otherwise), and such Class B Member reasonably determines that it has a Regulatory Problem, at such Class B Member’s request, the Company, at the sole cost and expense of such Class B Member, will offer to sell to such Class B Member non-voting securities (or, if the Company is not the proposed seller, will arrange for the exchange of any voting securities for non-voting securities immediately prior to or simultaneous with such sale) on the same terms as would have existed had such Class B Member acquired the securities so offered and immediately requested their exchange for non-voting securities pursuant to subsection (a) above.

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ARTICLE X
DISSOLUTION AND WINDING-UP

Section 10.1     Events of Dissolution. The Company shall be dissolved and its affairs shall be wound up upon the first to occur of any of the following:

(a)     the written consent of the Members representing a Super-Majority Vote to dissolve and terminate the Company;

(b)     the entry of a decree of judicial dissolution under Section 18-802 of the Act;

(c)     the occurrence of the Termination Date;

(d)     the disposition of all or substantially all of the Company’s business and Assets;

(e)     the issuance of a final, nonappealable court order which makes it unlawful for the business of the Company to be carried on; or

(f)     at any time there are no Members of the Company unless the business of the Company is continued in accordance with the Act.

Section 10.2     Distribution of Assets.

(a)     The Members hereby appoint the Managing Member to act as the liquidator upon the occurrence of one of the events in Section 10.1. Upon the occurrence of such an event, the liquidator will proceed diligently to wind up the affairs of the Company and make final distributions as provided herein and in the Act. The costs of liquidation will be borne by the Company. The liquidator may sell, and will use commercially reasonable efforts to obtain the best possible price for the sale of any or all Company property, including to Members. In no event, without the approval of Members by Super-Majority Vote of Members, will a sale to a Member be for an amount that is less than fair market value (determined by the Appraisal Method if the Members (by Super-Majority Vote) are unable to agree on the fair market value).

(b)     The steps to be accomplished by the liquidator are as follows:

(i)     As promptly as reasonably practicable after dissolution and again after final liquidation, the liquidator shall cause a proper accounting to be made by the Accounting Firm of the Company’s Assets, liabilities, and operations through the last day of the calendar month in which the dissolution occurs or the final liquidation is completed, as applicable.

(ii)     The liquidator shall pay from Company funds all of the debts and liabilities of the Company (including the Working Capital Loans) or otherwise make adequate provision for them (including the establishment of a cash escrow fund for contingent, conditional or unmatured liabilities in such amount and for such term as the liquidator may reasonably determine).

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(iii)     With respect to the remaining Assets of the Company:

(A)     the liquidator shall use all commercially reasonable efforts to obtain the best possible price and may sell any or all Company Assets (subject to any and all restrictions to which the Project is subject), including to the Members at such price, but in no event lower than the Fair Market Value thereof; and

(B)     with respect to all Company Assets that have not been sold, the Gross Asset Values of such Assets shall be determined pursuant to subparagraph (b) of the definition of Gross Asset Value.

(iv)     Any Company items of income and gain (including any such items attributable to the disposition or deemed disposition of Assets pursuant to Section 10.2(b)(iii) and PTCs) for the Tax Year during which the distribution of liquidation proceeds occurs that have not been allocated pursuant to the allocations set forth in Section 5.2(a) through (h) shall, subject to the limitation contained in Section 10.2(b)(iv)(C) hereof, first be allocated to each Member having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Members, until each Member has been allocated Company items of income and gain equal to any such deficit balance in its Capital Account and such deficit balance has thereby been eliminated provided, if the Company items of income and gain are insufficient to eliminate the deficit Capital Account balances of the Members, any Company items of income and gain (but not losses) shall be allocated first to the Class B Members; provided further, that if any Class B Member will have a deficit in its Capital Account as a result of the allocation of five percent (5%) of any Company items of losses associated with any PPA pursuant to Section 10.2(b)(iv)(C), then prior to such allocation, Company items of income and gain shall be further allocated to such Class B Member to the extent necessary to ensure such Class B Member will not have a deficit in its Capital Account after taking into account the allocation of any such losses. Any remaining Company items (including any items attributable to the disposition or deemed disposition of Assets pursuant to Section 10.2(b)(iii) and PTCs) for such Tax Year during which the distribution of liquidation proceeds occurs shall be allocated among the Members in such manner as to ensure that, to the greatest extent feasible, following these allocations, the balances in the Capital Accounts of the Members are expected to result in distributions pursuant to Section 10.2(b)(v) in accordance with the following target liquidation distributions:

(A)     first, to the Class B Members, pro rata in accordance with their Class B Units, until the Class B Member has achieved the Target Internal Rate of Return (for the avoidance of doubt, using the calculation rules and conventions of Section 7.11(a) through (d); and

(B)     thereafter, to the Class A Members and the Class B Members in accordance with the sharing ratios set forth in Section 6.1(a)(iii) hereof as being applicable after the Flip Date.

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(C)     Notwithstanding the foregoing, in the event that the allocations set forth in this Section 10.2(b)(iv) result in either (i) the Class A Members failing to be allocated at least one percent (1%) or (ii) the Class B Members failing to be allocated at least five percent (5%), of each material Company item for the Tax Year during which the distribution of liquidation proceeds occurs, Company items shall be reallocated among the Class B Members and the Class A Members, to the extent necessary, to cause (i) the Class A Members to be allocated at least one percent (1%) and (ii) the Class B Members to be allocated at least five percent (5%), of each material item of gross income, gain, loss, deduction and credit for the Tax Year during which the distribution of liquidation proceeds occurs.

(v)     After giving effect to all allocations (including those under Section 5.2 and Section 10.2(b)(iv)), all prior distributions (including those under Section 6.1) and all Capital Contributions (including those made on the Effective Date) for all periods, all remaining cash and property (including any Distributable Cash and liquidation proceeds) shall be distributed to the Members in accordance with the positive balances in their Capital Accounts.

(vi)     Any distribution to the Members in respect of their Capital Accounts pursuant to this Section 10.2 shall be made by the end of the Company taxable year in which a the event described in Section 10.1 occurs (or if later, within ninety (90) days after the date of such liquidating event).

(c)     The distribution of cash or property to a Member in accordance with the provisions of this Section 10.2 constitutes a complete return to the Member of its Capital Contributions and a complete distribution to the Member on account of its Membership Interest and all the Company’s property and constitutes a compromise to which all Members have consented pursuant to Section 18-502(b) of the Act.

Section 10.3      Deficit Capital Accounts.

(a)     Except as expressly provided in this Section 10.3, no Member shall be obligated to contribute cash to restore a deficit in its Capital Account balance.

(b)     In the event the Class B Members’ interests in the Company are “liquidated” within the meaning of Treasury Regulations Section 1.704-1(b)(2)(ii)(g), if a Class B Member has a deficit Capital Account balance in excess of the amount such Class B Member is deemed obligated to restore pursuant to the penultimate sentences of Treasury Regulations Section 1.704-2(g)(1) and 1.704-2(i)(5) (an “Adjusted Deficit Capital Account Balance”), calculated in each case in accordance with Section 10.2 and the other provisions of this Agreement without regard to such Class B Member’s obligation pursuant to this Section 10.3(b) (provided, that to the extent disregarding such obligation in calculating such amount is inconsistent with Law, such Class B Member’s obligation pursuant to this Section 10.3(b) shall be taken into account in such calculation), then such Class B Member shall be obligated to pay to the Company cash in an amount equal to Adjusted Deficit Capital Account Balance by the end of the Company taxable year during which the liquidation of the Company occurs, or if later, within ninety (90) days after the date of such liquidation; provided, however, that the restoration obligation of such Class B Member shall not be more than its DRO Amount. Each Class B Member shall have the right by written notice to the Company (the “DRO Notice”), at any time and in its sole discretion, to elect to increase its DRO Amount to the amount specified in such DRO Notice. Notwithstanding the foregoing, after such point in time at which the absolute value of a Class B Member’s Adjusted Deficit Capital Account Balance declines over the prior Tax Year, such Class B Member’s DRO Amount shall be adjusted downward (but not increased) at the end of each Tax Year to an amount equal to the lesser of (i) the dollar amount set forth in the latest of any DRO Notice given by such Class B Member, or (ii) the absolute value of such Class B Member’s Adjusted Deficit Capital Account Balance at the end of such Tax Year. Nothing contained in this Agreement shall obligate any Class B Member to issue a DRO Notice. A DRO Notice given by a Class B Member pursuant hereto shall be deemed to constitute a duly adopted amendment to this Agreement without any further action by any party. If any Class B Member issues a DRO Notice, the Tax Matters Partner shall prepare, or cause to be prepared by the Accounting Firm, a Tax Return that is consistent with such DRO Notice.

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(c)     In the event the Class A Members’ interests in the Company are “liquidated” within the meaning of Treasury Regulations Section 1.704-1(b)(2)(ii)(g), if a Class A Member has a deficit Capital Account balance in excess of the amount such Class A Member is deemed obligated to restore pursuant to the penultimate sentences of Treasury Regulations Section 1.704-2(g)(1) and 1.704-2(i)(5) (a “Class A Adjusted Deficit Capital Account Balance”), calculated in each case in accordance with Section 10.2 and the other provisions of this Agreement without regard to such Class A Member’s obligation pursuant to this Section 10.3(c) (provided, that to the extent disregarding such obligation in calculating such amount is inconsistent with Law, such Class A Member’s obligation pursuant to this Section 10.3(c) shall be taken into account in such calculation), then such Class A Member shall be obligated to pay to the Company cash in an amount equal to such Class A Adjusted Deficit Capital Account Balance by the end of the Company taxable year during which the liquidation of the Company occurs, or if later, within ninety (90) days after the date of such liquidation; provided, however, that the restoration obligation of such Class A Member shall initially not be more than $0; provided, further, that, notwithstanding any provision herein to the contrary, each Class A Member’s DRO Amount shall be not less than the amount of any deficit in such Class A Member’s Capital Account that results from cash distributions made to the Class A Member in a Tax Year that are not matched by an allocation of income or gain or an adjustment made under Treasury Regulations Section 1.704-1(b)(2)(iv)(m) to such Class A Member for such Tax Year (such deficit restoration obligation of a Class A Member, the “Class A Member’s DRO Amount”). Notwithstanding the foregoing, if the absolute value of the deficit in the Class A Member’s Capital Account declines at the end of a subsequent taxable year, the Class A Member’s DRO Amount shall be adjusted downward by a corresponding amount (subject to any DRO Notice issued by the Class A Member).

Section 10.4     In-Kind Distributions. There shall be no distribution of Assets of the Company in kind without the prior Super-Majority Vote of the Members.

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Section 10.5     Certificate of Cancellation.

(a)     When all debts, liabilities and obligations have been paid and discharged or adequate provisions have been made therefor and all of the remaining property and Assets have been distributed to the Members, a certificate of cancellation of the Certificate of Formation (the “Certificate of Cancellation”) shall be executed and filed by the liquidator with the Secretary of State of the State of Delaware, which certificate shall set forth the information required by Section 18-203 of the Act.

(b)     Upon the filing of the Certificate of Cancellation, the existence of the Company shall cease.

(c)     All costs and expenses in fulfilling the obligations under this Section 10.5 shall be borne by the Company.

ARTICLE XI
INDEMNIFICATION

Section 11.1     Indemnifications.

(a)     The Class A Member (the “Indemnifying Party”) agrees to indemnify, defend and hold harmless Class B Member Indemnified Parties (the “Indemnified Parties”) from and against any and all Class B Member Indemnified Costs.

(b)     No claim for indemnification may be made with respect to any breach (other than failure to pay an amount due) unless and until the aggregate amount of claims for which indemnification is (or previously has been) sought exceeds three hundred thousand dollars ($300,000); provided that, once such threshold amount of claims has been reached, the relevant Indemnified Party shall have the right to be indemnified for all such claims, including amounts that were not previously paid because such threshold amount had not been reached.

(c)     Notwithstanding anything to the contrary contained herein, the Class A Members’ indemnification obligations shall survive the Transfer of any Class A Membership Interests, to the extent that any claim for indemnification by a Class B Member Indemnified Party relates to the period of time prior to such Transfer.

Section 11.2     Direct Claims. In any case in which an Indemnified Party seeks indemnification under Section 11.1 which is not subject to Section 11.3 because no Third Party Claim is involved (a “Direct Claim”), the Indemnified Party shall notify the Indemnifying Party in writing of any amounts which such Indemnified Party claims are subject to indemnification under the terms of this Article XI. The failure of the Indemnified Party to exercise promptness in such notification shall not amount to a waiver of such claim, except to the extent the resulting delay materially and adversely prejudices the position of the Indemnifying Party with respect to such claim.

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Section 11.3     Third Party Claims.

(a)     An Indemnified Party shall give written notice to any Indemnifying Party within 30 days after it has actual knowledge of commencement or assertion of any action, proceeding, demand, or claim by a third party (collectively, a “Third Party Claim”) in respect of which such Indemnified Party may seek indemnification under Section 11.1. Such notice shall state the nature and basis of such Third Party Claim and the events and the amounts thereof to the extent known. Any failure so to notify an Indemnifying Party shall not relieve such Indemnifying Party from any liability that it, he, or she may have to such Indemnified Party under this Article XI, except to the extent the failure to give such notice materially and adversely prejudices such Indemnifying Party. In case any such action, proceeding or claim is brought against an Indemnified Party, so long as it has acknowledged in writing to the Indemnified Party that it is liable to the Indemnified Party for such Third Party Claim pursuant to this Section, the Indemnifying Party shall be entitled to participate in and, unless in the reasonable judgment of the Indemnified Party a conflict of interests between it and the Indemnifying Party may exist in respect of such Third Party Claim or such Third Party Claim entails a material risk of criminal penalties or civil fines or non-monetary sanctions or equitable remedies being imposed on the Indemnified Party (a “Third Party Penalty Claim”), to assume the defense thereof, with counsel selected by the Indemnifying Party and reasonably satisfactory to the Indemnified Party, and after notice from the Indemnifying Party to the Indemnified Party of its election so to assume the defense thereof, the Indemnifying Party shall not be liable to such Indemnified Party for any legal or other expenses subsequently incurred by the latter in connection with the defense thereof other than as expressly provided below in this Section 11.3; provided nothing contained herein shall permit any Indemnifying Party to control or participate in any Tax contest or dispute involving the Class B Member or any Affiliate of the Class B Member, or permit the Class B Member to control or participate in any Tax contest or dispute involving the Class A Member or any Affiliate of the Class A Member other than the Company; and, provided, further, the Parties agree that the handling of any tax contests involving the Company will be governed by Section 7.7.

(b)     In the event that (i) the Indemnifying Party advises an Indemnified Party that it will not contest a claim for indemnification hereunder, (ii) the Indemnifying Party fails, within thirty (30) days of receipt of any indemnification notice to notify, in writing, such Indemnified Party of its election, to defend, settle or compromise, at its sole cost and expense, any such Third Party Claim (or discontinues its defense at any time after it commences such defense) or (iii) in the reasonable judgment of the Indemnified Party, a conflict of interests between it and the Indemnifying Party exists in respect of such Third Party Claim or the action or claim is a Third Party Penalty Claim, then the Indemnified Party may, at its option, defend, settle or otherwise compromise or pay such action or claim or Third Party Claim. In any event, unless and until the Indemnifying Party elects in writing to assume and does so assume the defense of any such claim, proceeding or action, the Indemnifying Party shall be liable for the Indemnified Party’s reasonable costs and expenses arising out of the defense, settlement or compromise of any such action, claim or proceeding. The Indemnified Party shall cooperate fully with the Indemnifying Party in connection with any negotiation or defense of any such action or claim by the Indemnifying Party. The Indemnifying Party shall keep the Indemnified Party fully apprised at all times as to the status of the defense or any settlement negotiations with respect thereto. If the Indemnifying Party elects to defend any such action or claim, then the Indemnified Party shall be entitled to participate in such defense with counsel of its choice at its sole cost and expense; provided that any such participation of the Indemnified Party shall be at the Indemnifying Party’s sole cost and expense to the extent such participation relates to a Third Party Penalty Claim or if a conflict of interest between the Indemnified Party and the Indemnifying Party exists in respect of the Third Party Claim; and provided, further, that the Indemnifying Party shall not be responsible for the costs and expenses of more than one counsel for all Indemnified Parties. If the Indemnifying Party does not assume such defense, the Indemnified Party shall keep the Indemnifying Party apprised at all times as to the status of the defense; provided, however, that the failure to keep the Indemnifying Party so informed shall not affect the obligations of the Indemnifying Party hereunder.

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(c)     The Indemnifying Party shall not be liable for any settlement of any action, claim or proceeding effected without its written consent; provided, however, that the Indemnifying Party shall not unreasonably withhold, delay or condition its consent.

(d)     Notwithstanding anything in this Section 11.3 to the contrary, the Indemnifying Party shall not, without the Indemnified Party’s prior written consent, settle or compromise any claim or consent to entry of judgment in respect thereof which imposes any criminal liability or civil fine or sanction or equitable remedy on the Indemnified Party or which does not include, as an unconditional term thereof, the giving by the claimant or the plaintiff to the Indemnified Party, a release from all liability in respect of such claim.

Section 11.4     Certain Obligation of the Class A Members. Following the delivery of a notice of Claim pursuant to Section 11.2 or Section 11.3 hereof, as applicable, and providing there is a reasonable basis for such Claim, and the amount of the Claim is reasonable in light of the basis of the Claim, then commencing with the first cash distribution under Section 6.1 hereof made by the Company following (a) the date the Indemnifying Party receives notice of a Direct Claim or (b) the expiration of the 30-day period referred to in Section 11.3(b)(ii) hereof, and in either case until all payments owed by the Class A Member to any Class B Member Indemnified Party pursuant to Section 11.2 or to any other Person pursuant to Section 11.3 hereof have been paid in full (or such lesser amount as shall have been agreed in writing by the Class B Member), any distributions as to which the Class A Member would otherwise be entitled pursuant to Section 6.1 hereof shall not be paid to the Class A Member until the Class B Member Indemnified Party or other Person, as the case may be, shall have received all amounts owed to such Class B Member Indemnified Party or other Person, as the case may be, and all Distributable Cash otherwise payable to the Class A Member, shall (to the extent that such Claim is not subject to any good faith dispute) be paid to the Class B Member Indemnified Party or to such other Person; provided, that the Class A Member shall use its best efforts to resolve any such good faith dispute within sixty (60) days.

Section 11.5     After-Tax Basis. For tax reporting purposes, to the maximum extent permitted by the Code, each Party will treat all amounts paid under any of the provisions of this Article XI as an adjustment to the Capital Contribution for the Membership Interest (or otherwise as a non-taxable reimbursement, contribution or return of capital, as the case may be). To the extent any such indemnification payment is includable as income of the Indemnified Party as determined by agreement of the Parties, or if there is no agreement, by an opinion of a nationally recognized tax counsel selected jointly by the Parties that such amount “should” be includable as income of the recipient, the amount of the payment shall be increased by the amount of any federal income tax required to be paid by the Indemnified Party or its Affiliates on the receipt or accrual of the indemnification payment, including, for this purpose, the amount of any such Tax required to be paid by the Indemnified Party on the receipt or accrual of the additional amount required to be added to such payment pursuant to this Section 11.5, assuming full taxability, using an assumed tax rate equal to the Highest Marginal Rate. Both Parties shall have the opportunity to comment on the opinion delivered in accordance with the foregoing sentence. If an opinion is delivered in accordance with this Section 11.5, the Indemnified Party shall report the relevant indemnification payments as income consistent with such opinion and otherwise act in a manner consistent with such opinion. Any payment made under this Article XI shall be reduced by the present value (as determined on the basis of a discount rate equal to the Target Internal Rate of Return and the same assumptions about taxability and tax rates) of any federal income tax benefit to be realized by the Indemnified Party or its Affiliates by reason of the facts and circumstances giving rise to such indemnification.

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Section 11.6     No Duplication. Any liability for indemnification under this Article XI shall be determined without duplication of recovery. Without limiting the generality of the prior sentence, if a statement of facts, condition or event constitutes a breach of more than one representation, warranty, covenant or agreement which is subject to the indemnification obligation in Section 11.1, only one recovery of Class B Member Indemnified Costs shall be allowed.

Section 11.7     Survival. All representations and warranties in this Agreement shall survive until the final date for any assertion of claims as forth in Section 11.8.

Section 11.8     Final Date for Assertion of Indemnity Claims. All claims by a Class B Member Indemnified Party for indemnification pursuant to this Article XI resulting from breaches of representations or warranties under the Contribution Agreement shall be forever barred unless the Class A Member is notified on or prior to the second anniversary of the Closing Date, except that (i) (w) the representations and warranties made as a condition precedent to the Closing and set forth in Sections 3.1 (Organization, Good Standing, Etc. of ONI and OrLeaf), 3.2 (Organization, Good Standing, Etc. of the Company and Subject Companies), 3.3 (Authority) and 3.6 (Ownership) of the Contribution Agreement shall survive indefinitely, (x) the representations and warranties set forth in Section 3.9 (Tax Matters) of the Contribution Agreement shall survive for 60 days after the applicable statute of limitations, (y) the representations and warranties set forth in Section 3.30 (Background Materials) of the Contribution Agreement shall survive for four years following the Closing Date, and (z) the representations and warranties set forth in Section 3.13 (Environmental Matters) of the Contribution Agreement shall survive for four years following the Closing Date; provided, that, if written notice of a claim for indemnification has been given by such Class B Member Indemnified Party on or prior to the applicable date described above, then the obligation of the Class A Member to indemnify such Class B Member Indemnified Party pursuant to this Article XI shall survive with respect to such claim until such claim is finally resolved.

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Section 11.9     Mitigation and Limitations on Losses. Notwithstanding anything to the contrary contained herein:

(a)     Reasonable Steps to Mitigate. The Indemnified Party will take, at the Indemnifying Party’s cost and expense, all commercially reasonable steps identified by the Indemnifying Party to mitigate all Class B Member Indemnified Costs, which steps may include availing itself of any defenses, limitations, rights of contribution, claims against third Persons and other rights at law or equity. The Indemnified Party will provide such evidence and documentation of the nature and extent of the Class B Member Indemnified Costs as may be reasonably requested by the Indemnifying Party.

(b)     Net of Insurance Benefits. All Losses shall be limited to the amount of actual out-of-pocket damages sustained by the Indemnified Party by reason of any breach or nonperformance hereunder, net of insurance recoveries from insurance policies of the Subject Companies (including under the existing title policies).

(c)     No Consequential Damages. Except as otherwise provided in the definition of “Class B Member Indemnified Costs” relating to disallowed PTCs and other Tax deductions, Class B Member Indemnified Costs shall not include, and the Indemnifying Party shall have no obligation to indemnify any Indemnified Parties for or in respect of any punitive, consequential, special, incidental or exemplary damages of any nature (other than punitive, consequential, special, incidental or exemplary damages recovered against an Indemnified Party by a Person other than a Party and subject to indemnification hereunder).

Section 11.10     Sole Remedy. Without in any way limiting the Sponsor Guaranty, the Parties agree that the remedies under this Article XI are the sole and exclusive remedies under this Agreement and the Contribution Agreement for the recovery of monetary damages with respect to any breach or failure to perform any covenant or agreement set forth in this Agreement or the Contribution Agreement or any breach of any representation or warranty set forth in this Agreement or the Contribution Agreement other than fraud, gross negligence or willful misconduct.

Section 11.11     Payment of Indemnification Claims. Subject to Section 11.4, all claims for indemnification shall be paid by the Indemnifying Party in immediately available funds in U.S. Dollars. Subject to Section 11.4, payments for indemnification claims shall be made promptly after any final determination of the amount of such claim is made by a court of competent jurisdiction (or by agreement of the Parties involved).

ARTICLE XII
COVENANTS

Section 12.1     Geothermal Matters.

(a)     The Members hereby agree that each Project currently utilizes specific geothermal resources set forth in the Independent Engineer’s report, located on such land set forth in the surveys, each a “Known Project Geothermal Resource Area.”

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(b)     (i) other than for the purpose of compliance with the Material Contracts, the Class A Member shall allocate all geothermal fluid, brine or other geothermal elements from any Known Project Geothermal Resource, at all times in a manner so as to at least achieve the assumptions and projections in the Base Case Model with respect to the PTC Eligible Projects, and (ii) except as otherwise provided in paragraph (c) of this Section 12.1, and only until the Flip Date, (A) the Class A Member shall not develop, construct, own or operate, and shall ensure that none of its Affiliates develop, construct, own or operate, a new geothermal power plant utilizing geothermal resources that form part of any Known Project Geothermal Resource Area, and (B) other than for the purpose of compliance with the Material Contracts, the Class A Member shall not, and shall ensure that none of its Affiliates, direct, divert or provide to, or allow to be used by, another Person or for another geothermal power plant, geothermal fluid, brine or other geothermal elements from any Known Project Geothermal Resource Area.

(c)     The restrictions contained in paragraph (b)(ii) of this Section 12.1 shall not apply if the Class A Member delivers to the Class B Member a certificate from GeothermEx, Inc. (or other geothermal consultant acceptable to the Class B Member), in form and substance reasonably acceptable to the Class B Member, to the effect that the sustainable operation at the levels of production and PTCs produced assumed in the Base Case Model of the existing Projects owned by the Subject Companies will not be adversely affected by (i) the development, construction and operation of the planned new geothermal power plant (in the case of clause (ii)(A) of Section 12.1(b)) or (ii) such redirection, diversion or provision of geothermal elements (in the case of clause (ii)(B) of Section 12.1(b)).

Section 12.2     Compliance with Senior Notes and Certain Other Material Contracts.

(a)     The Managing Member shall take such actions (or cause such actions to be taken), acting in accordance with the Prudent Operator Standard, to (a) comply, or to cause the Company and/or the Subject Companies, as applicable, to comply in all material respects with the terms and conditions of the Senior Notes and Loan Documents (as defined in the OFC2 Note Purchase Agreement), and (b) cause the Subject Companies to perform and observe their respective covenants and obligations under the Material Contracts to which they are party except where the failure to do so could not reasonably be expected to result in a Material Adverse Effect; provided, (i) that it shall not be a breach of the Managing Member’s obligations under this Section 12.2(a) if any failure to comply with any obligation under the Senior Notes and Loan Documents (as defined in the OFC2 Note Purchase Agreement) or the other Material Contracts, as the case may be, is not reasonably susceptible to cure within the requisite time period (if any) by the Managing Member, Company or relevant Subject Company, as the case may be, or funds are not available from Distributable Cash (as determined prior to subtracting the cash contemplated in subclause (b) of the definition of Distributable Cash) as needed to effect such cure, (ii) the Managing Member shall have no obligation to cause Company funds to be applied towards any payments due and owing under the applicable Senior Notes or with respect to any Project Company’s other obligations (in either such case only to the extent that adequate funds are not available at such Project Company) other than from Distributable Cash available in accordance with this Agreement, and (iii) for the avoidance of doubt, the Managing Member shall have no obligation to use its own funds to perform any obligation hereunder.

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(b)     Ormat (or an Affiliate) has posted certain credit support in connection with the Senior Notes. In the event Ormat (or an Affiliate) incurs reimbursement obligations or loans resulting from draws of such credit support, or otherwise advances cash reserves, provides a guaranty, letter of credit, surety or posts other collateral, such reimbursement obligations, loans, guaranties, letter of credits, sureties or cash advances shall be deemed an obligation of Ormat, individually, and shall not be considered a Working Capital Loan or subject to any priority distribution or fee.

(c)     To the extent that under the terms of any of the Loan Documents (as defined in the OFC2 Note Purchase Agreement) (i) any credit support previously provided in connection with the Senior Notes has been released because it is no longer required, or (ii) cash or cash equivalents deposited in any required reserve account have been substituted with any letter of credit or other credit support provided by the Class A Member or any Affiliate thereof (other than the Company or any Subject Company), or (iii) any required reserve amount is reduced or is no longer required to be maintained and is permitted to be distributed as a Restricted Payment, then, in each such case, and notwithstanding any other provision of this Agreement to the contrary, any such credit support, cash or cash equivalents, or funds comprising amounts reduced from or released as a reserve requirement shall be distributed by the Company in full to the Class A Member only, but only to the extent such credit support, cash or cash equivalents was in place as of the Effective Date.

Section 12.3     Certain Tax Matters.

(a)     Each Member hereby covenants to the Company and the other Member that it will be a “United States person” as defined in Section 7701(a)(30) of the Code, and will not be subject to withholding under Section 1446 of the Code.

(b)     Each Member hereby covenants to the Company and the other Member that it will be an Unrelated Person.

(c)     Each Member hereby covenants to the Company and the other Member that it will not take any action that would cause the Assets of the Company or any Subject Company to constitute tax-exempt use property within the meaning of Section 168(h) of the Code.

(d)     The Managing Member hereby covenants that each Project shall be located in its entirety in the United States.

(e)     The Managing Member hereby covenants that, for purposes of Section 45(b)(3) of the Code, there shall not be any (i) grant provided by the United States, any state or any political subdivision of a state for use in connection with any PTC Eligible Project, (ii) issue of state or local government obligations used to provide financing for any PTC Eligible Project the interest on which is exempt from federal income tax under Section 103 of the Code, (iii) subsidized energy financing provided (directly or indirectly) under a federal, state, or local program provided in connection with any PTC Eligible Project or (iv) other credit with respect to any property that is part of a PTC Eligible Project, in each case unless agreed to by a Major Decision or otherwise consented to or claimed by the Class B Member, in each case, other than as a result of an act or omission of the Class B Member.

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(f)     The Managing Member hereby covenants that to the extent each PTC Eligible Project shall derive energy, it shall derive such energy from a geothermal reservoir consisting of natural heat that is stored in rocks or in an aqueous liquid or vapor.

(g)     The Managing Member hereby covenants that it will not make capital improvements to any PTC Eligible Project prior to the Flip Date, without consent of the Class B Member, to the extent that the total cost of capital expenditures with respect to the PTC Eligible Project made after the relevant date set forth on Schedule 3.9(f) of the Contribution Agreement would exceed four times the value of the equipment that was part of the PTC Eligible Project on such date.

(h)     The Managing Member hereby covenants that it will sell to an Unrelated Person all electricity generated by any PTC Eligible Project that is capable of being sold and that no more of such electricity than is necessary will be used to satisfy the load requirements of any Project.

(i)     The Managing Member hereby covenants that in each Tax Year the Company shall continue to claim cost recovery deductions in accordance with Section 611 of the Code and the applicable Treasury Regulations for depletion of the Steam Resource.

(j)     The Managing Member hereby covenants that to the extent the Company pays or incurs any intangible drilling and development costs, the Managing Member will provide notice to the Class B Member within sixty (60) days of the Company incurring any such costs, which notice shall provide the amount of such intangible drilling and development costs and describe the Class B Member’s option to make an election with respect to such costs pursuant to Section 59(e) of the Code.

(k)     The Managing Member hereby covenants that it will not cause the Company or any Subject Company to (x) apply for a grant with respect to any PTC Eligible Project from the U.S. Treasury Department under Section 1603 of the American Recovery and Reinvestment Tax Act of 2009 or (y) claim an investment tax credit under Section 48 of the Code with respect to any PTC Eligible Project or any portion thereof.

ARTICLE XIII
MISCELLANEOUS

Section 13.1     Notices. Unless otherwise provided herein, any offer, acceptance, election, approval, consent, certification, request, waiver, notice or other communication required or permitted to be given hereunder (collectively referred to as a “Notice”), shall be in writing and deemed given if delivered personally, by a nationally recognized overnight courier, by facsimile, or mailed by registered or certified mail (return receipt requested) directed to the intended recipient at the address of such Member set forth on Schedule 4.2(d) attached hereto (as applicable) or at such other address as any Member hereafter may designate to the others in accordance with a Notice under this Section 13.1. A Notice and other communications given in accordance herewith shall be deemed given (i) on the date of delivery, if hand delivered, (ii) on the date of receipt, if faxed (provided a hard copy of such transmission is dispatched by first class mail within 48 hours), (iii) three Business Days after the date of mailing, if mailed by registered or certified mail, return receipt requested, and (iv) one Business Day after the date of sending, if sent by a nationally recognized overnight courier; provided, that a notice given in accordance with this Section but received on any day other than a Business Day or after business hours in the place of receipt, will be deemed given on the next Business Day in that place.

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Section 13.2     Amendment. Except for a Transfer of Membership Interests and the admission of a new Member in accordance with the terms of this Agreement, this Agreement may be changed, modified or amended only by an instrument in writing duly executed by all of the Members.

Section 13.3     Partition. Each of the Members hereby irrevocably waives, to the extent it may lawfully do so, any right that such Member may have to maintain any action for partition with respect to the Company property.

Section 13.4     Waivers and Modifications. Any waiver or consent, express, implied or deemed, to or of any breach or default by any Person in the performance by that Person of its obligations with respect to the Company or any action inconsistent with this Agreement is not a consent or waiver to or of any other breach or default in the performance by that Person of the same or any other obligations of that Person with respect to the Company or any other such action. Failure on the part of a Person to insist in any one or more instances upon strict performance of any provisions of this Agreement, to take advantage of any of its rights hereunder, or to declare any Person in default with respect to the Company, irrespective of how long that failure continues, does not constitute a waiver by that Person of its rights with respect to that Person or its rights with respect to that default until the applicable statute of limitations period has lapsed. All waivers and consents hereunder shall be in writing duly executed by Members representing a Super-Majority Vote of the Members affected by such waiver or consent and shall be delivered to the other Members in the manner set forth in Section 13.1.

Section 13.5     Severability. Except as otherwise provided in the succeeding sentence, every term and provision of this Agreement is intended to be severable, and if any term or provision of this Agreement is illegal or invalid for any reason whatsoever, such illegality or invalidity shall not affect the legality or validity of the remainder of this Agreement. The preceding sentence shall be of no force or effect if the consequence of enforcing the remainder of this Agreement without such illegal or invalid terms or provision would be to cause any Party to lose the benefit of its economic bargain.

Section 13.6     Successors; No Third-Party Beneficiaries. This Agreement is binding on and inures to the benefit of the Members and their respective heirs, legal representatives, successors and permitted assigns. Nothing in this Agreement shall provide any benefit to any third party or entitle any third party to any claim, cause of action, remedy or right of any kind, it being the intent of the Members that this Agreement shall not be construed as a third-party beneficiary contract. To the fullest extent permitted by law, no creditor or other third party having dealings with the Company shall have the right to pursue any other right or remedy hereunder or at law or in equity, it being understood and agreed that the provisions of this Agreement shall be solely for the benefit of, and may be enforced solely by, the parties hereto and their respective successors and permitted assigns. None of the rights of the Members herein set forth to make Capital Contributions or loans to the Company shall be deemed an Asset of the Company for any purpose by any creditor or other third party, nor may such rights or obligations be sold, transferred or assigned by the Company or pledged or encumbered by the Company to secure any debt or other obligation of the Company or of any of the Members.

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Section 13.7     Entire Agreement. This Agreement, including the Schedules, exhibits and annex attached hereto or incorporated herein by reference, constitutes the entire agreement of the Members with respect to the matters covered herein. This Agreement supersedes all prior agreements and oral understandings among the parties hereto with respect to such matters.

Section 13.8     Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware, excluding any conflict of laws rule or principle that might refer the governance or construction of this Agreement to the law of another jurisdiction.

Section 13.9     Further Assurances. In connection with this Agreement and the transactions contemplated hereby, each Member shall execute and deliver any additional documents and instruments and perform any additional acts that may be reasonably required or useful to carry out the intent and purpose of this Agreement and as are not inconsistent with the terms hereof.

Section 13.10     Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be an original but all of which together will constitute one instrument, binding upon all parties hereto, notwithstanding that all of such parties may not have executed the same counterpart.

Section 13.11     Dispute Resolution.

(a)     Except as provided in Section 13.11(b), in the event a dispute, controversy or claim arises hereunder, the aggrieved party will promptly provide written notification of the dispute to the other party within ten days after such dispute arises. A meeting will be held promptly between the parties, attended by representatives of the parties with decision-making authority regarding the dispute, to attempt in good faith to negotiate a resolution of the dispute. If the dispute, controversy or claim involves approval of any Annual Budget, the Independent Engineer (or if the Independent Engineer is unable or unwilling to act for any reason, another recognized firm of independent engineers experienced with geothermal power projects comparable to the Projects selected by Super-Majority Vote) will be invited to participate in the meeting and advise the representatives of the parties involved concerning the Independent Engineer’s opinions concerning any such dispute, controversy or claim involving the Annual Budget. If the parties are not successful in resolving a dispute within 21 days, the parties will thereafter be entitled to pursue all such remedies as may be available to them.

(b)     If the Class B Member disputes the Managing Member’s calculation of any items in any Target Internal Rate of Return calculation, the Class B Member shall notify the Managing Member and other Members not more than ten Business Days after the Class B Member has received the applicable Target Internal Rate of Return calculation notice from the Managing Member. If any Class B Member shall disagree with the Tax Matters Partner that a proposed Tax Return constitutes either a Consistent Return or an Excepted Non-Conforming Return as provided in Section 7.6(c)(i), such Class B Member shall so notify the Managing Member in accordance with Section 7.6(d).

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(i)     In such event, the Members and the Managing Member shall consider the issues raised or in dispute and discuss such issues with each other and attempt to reach a mutually satisfactory agreement. If notice of dispute is not given by the Class B Member within such period, any calculation in the Target Internal Rate of Return will be final and binding on the Members.

(ii)     If the dispute as to the Managing Member’s calculations is not promptly resolved within ten Business Days of such notification of the dispute, the Class B Member and the Managing Member shall each promptly present their interpretations to an Independent Accounting Firm, and shall instruct the Independent Accounting Firm to determine the correct amount of the calculations in dispute and to resolve the dispute promptly, but in no event more than twenty Business Days after having the dispute submitted to it. The Independent Accounting Firm will make a determination as to each of the items in dispute, which must be (A) in writing, (B) furnished to each Member and the Managing Member and (C) made in accordance with this Agreement, and which determination, absent manifest error, will be conclusive and binding on all Members. Each Member shall use reasonable efforts to cause the Independent Accounting Firm to render its decision as soon as reasonably practicable, including by promptly complying with all reasonable requests by the Independent Accounting Firm for information, books, records and similar items.

(iii)     In the event the Independent Accounting Firm determines that any of the calculations in dispute was incorrect in any material respect, the fees and expenses of the Independent Accounting Firm shall be borne by the Class A Member. In all other cases the fees and expenses of the Independent Accounting Firm shall be borne by the Class B Member disputing any of the calculations.

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Section 13.12     Confidentiality.

The Members shall, and shall cause their Affiliates and their respective stockholders, members, Subsidiaries and Representatives to, hold confidential and not use in any manner detrimental to the Company or any Member all information they may have or obtain concerning Ormat, OrLeaf, the Company, JPM (and its Affiliates) and their respective Assets, business, operations or prospects or this Agreement (the “Confidential Information”); provided, however, that Confidential Information shall not include information that (a) becomes generally available to the public other than as a result of a disclosure by a Member or any of its Representatives, (b) becomes available to a Member or any of its Representatives on a nonconfidential basis prior to its disclosure by the Company or its Representatives, (c) is required or requested to be disclosed by a Member or any of its Affiliates or their respective stockholders, members, Subsidiaries or Representatives as a result of any applicable Legal Requirement or rule or regulation of any stock exchange, or (d) is required or requested by the IRS in connection with the Projects or PTCs relating thereto, including in connection with a request for any private letter ruling, any determination letter or any audit. Additionally, the Parties may disclose to any and all Persons, without limitations of any kind, the tax treatment and tax structure of the transactions contemplated by this Agreement and all materials of any kind (including opinions or other tax analyses) that are provided to it relating to such tax treatment and tax structure; provided, however, that no party hereto shall be permitted to disclose such tax treatment in violation of federal or state securities laws. The preceding sentence is intended to cause the transactions contemplated hereby to be treated as not having been offered under conditions of confidentiality for purposes of Treasury Regulations Section 1.6011-4(b)(3) (or any successor provision) promulgated under Section 6011 of the Code, and shall be construed in a manner consistent with such purpose. If such party becomes compelled by legal or administrative process to disclose any Confidential Information, such party will provide the other Members with prompt Notice so that the other Members may seek a protective order or other appropriate remedy or waive compliance with the non-disclosure provisions of this Section 13.12 with respect to the information required to be disclosed. If such protective order or other remedy is not obtained, or such other Members waive compliance with the non-disclosure provisions of this Section 13.12 with respect to the information required to be disclosed, the first party will furnish only that portion of such information that it is advised, by opinion of counsel, is legally required to be furnished and will exercise reasonable efforts, at the other Members’ expense, to obtain reliable assurance that confidential treatment will be accorded such information, including, in the case of disclosures to the IRS described in clause (d) above, to obtain reliable assurance that, to the maximum extent permitted by applicable Legal Requirements, such information will not be made available for public inspection pursuant to Section 6110 of the Code. Nothing herein shall be construed as prohibiting a party hereunder from using such Confidential Information in connection with (i) any claim against another Member hereunder, (ii) any exercise by a party hereunder of any of its rights hereunder and (iii) a disposition by a Member of all or a portion of its Membership Interest or a disposition of an equity interest in such Member or its Affiliates, provided, that, such potential purchaser shall have entered into a confidentiality agreement with respect to Confidential Information on customary terms used in confidentiality agreements in connection with corporate acquisitions before any such information may be disclosed. In addition, each Member hereby acknowledges that (i) the financial statements of the Company furnished to Members from time to time are confidential and may constitute material, non-public information concerning Affiliates of the Company or their securities under the United States federal securities laws; (ii) the United States federal securities laws, among other things, prohibit certain persons in possession of material, non-public information concerning companies or securities from buying or selling securities issued by those companies or disclosing that material, nonpublic information to others who buy or sell those securities while in possession of that information (or disclose that information to others who buy or sell); and (iii) each Member has a duty to comply with applicable United States federal securities laws.

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(a)     The Members acknowledge that the Class B Member, together with its associated companies, is a global financial services firm (the “Global Financial Services Firm”) engaged in the securities, investment management and credit services businesses. The Global Financial Services Firm’s securities business is engaged in securities underwriting, trading, brokerage activities, foreign exchange, commodities and derivatives trading, as well as providing investment banking, financing and financial advisory services. In the ordinary course of its trading, brokerage and financing activities, the Global Financial Services Firm may at any time hold long or short positions, and may trade or otherwise effect transactions, for its own account or the accounts of Affiliates of the Company, in debt or equity securities or senior loans of Affiliates of the Company or in any related derivative instrument. The Global Financial Services Firm, its respective directors and officers may also at any time invest on a principal basis or manage funds that invest on a principal basis, in debt or equity securities of any company that may be an Affiliate of the Company, or in any currency or commodity that may be involved in this transaction, or in any related derivative instrument. Further, the Global Financial Services Firm may at any time carry out ordinary course brokering activities for any company that may be an Affiliate of the Company.

(b)     The Members also acknowledge that the Global Financial Services Firm, its respective directors and officers, may from time to time perform various investment banking, commercial banking and financial advisory services for clients and customers who may have conflicting interests with respect to the Company. Each Member hereby acknowledges and agrees that, by reason of law or duties of confidentiality owed to other persons or the rules of any regulatory authority, the Global Financial Services Firm may be prohibited from disclosing information to Members (or such disclosure may be inappropriate), including information as to the Global Financial Services Firm’s possible interests as described in this paragraph and information received pursuant to client relationships.

Section 13.13     Joint Efforts. To the fullest extent permitted by law, neither this Agreement nor any ambiguity or uncertainty herein will be construed against any of the parties hereto, whether under any rule of construction or otherwise. On the contrary, this Agreement has been prepared by the joint efforts of the respective attorneys for, and has been reviewed by, each of the parties hereto.

Section 13.14     Specific Performance. The Members agree that irreparable damage may result if this Agreement is not performed in accordance with its terms, and the Members agree that any damages available at law for a breach of this Agreement may not be an adequate remedy. Therefore, to the extent that damages available at law for a breach of this Agreement are an inadequate remedy, to the fullest extent permitted by law, the provisions hereof and the obligations of the Members hereunder may be enforceable in a court of equity, or other tribunal with jurisdiction, by a decree of specific performance, and appropriate injunctive relief may be applied for and granted in connection therewith. Such remedies and all other remedies provided for in this Agreement shall, however, be cumulative and not exclusive and shall be in addition to any other remedies that a Member may have under this Agreement, at law or in equity.

Section 13.15     Survival. All indemnities and reimbursement obligations made pursuant to this Agreement shall survive dissolution and liquidation of the Company until expiration of the longest applicable statute of limitations (including extensions and waivers) with respect to the matter for which a Person would be entitled to be indemnified or reimbursed, as the case may be.

Section 13.16     Letter of Credit Reimbursement Obligations.

(a)     In the event that Ormat or an Affiliate incurs reimbursement obligations or loans resulting from draws on any credit support (other than the Sponsor Guaranty) provided on behalf of any Subject Company, or otherwise advances cash reserves or posts other collateral, in each case, other than for purposes of complying with credit support or reserve requirements under the Loan Documents (as such term is defined in the OFC2 Note Purchase Agreement), such reimbursement obligations, loans or cash advances shall be deemed an unsecured loan to the Company or Project Company, as applicable, by Ormat or such Affiliate, as applicable, to be repaid out of available cash flow of the Company or such Project Company, as applicable before any distributions to the members of such entity. In any case where Ormat or an Affiliate incurs such loan, such loan shall bear interest and shall otherwise have terms and conditions applicable to Working Capital Loans, excluding any limitations on the aggregate principal amount outstanding on Working Capital Loans. In any case where any Person other than Ormat or an Affiliate incurs such loan resulting from draws on any such Credit Support provided on behalf of the Subject Companies, such loan shall bear interest and shall otherwise have terms and conditions applicable to the credit or other facility made available by such Person to Ormat or an Affiliate.

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(b)     In the event that Ormat or an Affiliate provides on behalf of any Subject Company any guaranty, letter of credit or surety bond (other than the Sponsor Guaranty), in each case other than for purposes of complying with credit support or reserve requirements under the Loan Documents (as such term is defined in the OFC2 Note Purchase Agreement), the entity providing such guaranty, letter of credit or surety bond, if not a Class B Member, shall provide to the Class B Members within ten Business Days an executed copy of such guaranty, letter of credit or surety bond and Ormat or such Affiliate will be entitled to (i) receive a fee (the “Guaranty Fee”) which fee shall be comparable to a fee chargeable for providing such guaranty, letter of credit or surety bond to a project company rated below investment grade (or not rated), on a non-recourse basis, that may be arranged in an arm’s length transaction by a guarantor which would be deemed to have a credit rating of at least BBB+ and taking into account the amount of the underlying obligation being guaranteed and the length of time the guarantee will be outstanding, and (ii) compensation for the costs and expenses (including reasonable legal fees) incurred in connection with effecting, maintaining and renewing such guaranty, letter of credit or surety bond.

(c)     To the extent any such credit support, guaranty, letter of credit, or reserve requirement described in clause (a) above is subsequently released to any Subject Company, such credit support, guaranty, letter of credit or funds comprising a released reserve shall be distributed, notwithstanding any other provision in this Agreement to the contrary, in full to the Class A Member.

Section 13.17     Recourse Only to Member. Subject to the Sponsor Guaranty, the sole recourse of the Company for performance of the obligations of any Member hereunder shall be against such Member and its Assets and not against any Assets or property of any present or future stockholder, partner, member, officer, employee, servant, executive, director, agent, authorized representative or Affiliate of such Member.

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IN WITNESS WHEREOF, the parties, each a Member, have caused this Amended and Restated Limited Liability Company Agreement to be signed by their respective duly authorized officers as of the date first above written.

ORLEAF LLC

By:     /s/ Connie Stechman                                          

Name:   Connie Stechman

Title:     Secretary

JPM CAPITAL CORPORATION

By:     /s/ Anand Dandapani                                          

Name:     Anand Dandapani

Title:       Executive Director

[Signature Page to LLC Agreement of Opal Geo LLC]

Annex I

Definitions

“20-Year IRR Rate” means an after-tax internal rate of return of eleven and ninety-nine hundredths percent (11.99%) through the twentieth (20th) anniversary of the Closing Date calculated using the “XIRR” function on Microsoft Office Excel 2010 (or the same function in any subsequent version of Microsoft Office Excel).

“Accounting Firm” means the Company’s primary independent accounting firm, which shall be any of Deloitte Touche Tohmatsu, Ernst & Young, KPMG International, Pricewaterhouse Coopers or any nationally-recognized Affiliate thereof, at the Managing Member’s election, or such other firm of certified public accountants approved by Members representing a Super-Majority Vote.

“Act” means the Delaware Limited Liability Company Act, Delaware Code Ann. 6, Sections 18-101, et seq. and any successor statute, as the same may be amended from time to time.

“Adjusted Capital Account” means the Capital Account of a Member (a) increased by the amount of potential deficit that the Member is deemed obligated to restore, calculated as described in the last sentence of Treasury Regulation Section 1.704-2(g)(1) and the last sentence of Treasury Regulation Section 1.704-2(i)(5), (b) increased by the amount of any deficit restoration obligation to which the Member has agreed under Section 10.3(b), and (c) decreased by the items described in Treasury Regulation Section 1.704-1(b)(2)(ii)(d)(4), (5) and (6).

“Adjusted Deficit Capital Account Balance” has the meaning set forth in Section 10.3(b).

“Affiliate” of a specified Person means any Person that directly or indirectly through one or more intermediaries controls, is controlled by, or is under common control with, such specified Person. As used in this definition of Affiliate, the term “control” of a specified Person including, with correlative meanings, the terms, “controlled by” and “under common control with,” means (a) the ownership, directly or indirectly, of fifty percent (50%) or more of the equity interest in a Person or (b) the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise; provided, however, that notwithstanding the foregoing, for purposes of this Agreement, the Company will be deemed not to be an Affiliate of any Member; provided, further, that for purposes of Section 9.4(a)(iv) of this Agreement (and for no other purpose), any direct or indirect owner of an equity interest in OrLeaf shall be considered an Affiliate of OrLeaf.

“Agreement” means this Amended and Restated Limited Liability Company Agreement (and all schedules, annexes and exhibits hereto), as the same may be amended, supplemented or replaced from time to time.

“Annual Budget” has the meaning set forth in Section 7.1(b).

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“Anti-Corruption Laws” has the meaning given to such term in the Contribution Agreement.

“Appraisal Method” shall mean one appraiser shall be appointed by the Class A Member and one appraiser shall be appointed by the Class B Members, in each case, within 15 days of a party invoking the procedure described in this definition, which appraisers shall attempt to agree upon the fair market value of the Class B Membership Interests. If either the Class A Member or the Class B Members do not appoint their respective appraiser within five days after the end of the 15-day period referenced in the immediately preceding sentence, the determination of the appraiser appointed by the other Person (if so appointed within such period) shall be conclusive and binding on the Members. If the appraisers appointed by the Class A Member and the Class B Members are unable to agree upon the fair market value of the Class B Membership Interests within 30 days after the appointment of the second of such appraisers, the two appraisers shall appoint a third appraiser. In such case, the average of the determinations of the three appraisers shall be conclusive and binding on the Members, unless the determination of one independent appraiser is disparate from the middle determination by more than twice the amount by which the third determination is disparate from the middle determination, in which case the determination of the most disparate appraiser shall be excluded, and the average of the remaining two determinations shall be conclusive and binding on the Members.

“Approved Transferee” means any Person that (a) is an Affiliate of any Class B Member, or (b) (i) (x) satisfies the requirements hereunder applicable to all Transfers of Class B Membership Interests and (y) is not a Competitor, or (ii) is a Person approved by OrLeaf (such approval not to be unreasonably withheld or delayed).

“Assets” means all right, title and interest of a Person in land, properties, buildings, improvements, fixtures, foundations, assets and rights of any kind, whether tangible or intangible, real, personal or mixed, including contracts, leases, easements, equipment, systems, books, data, reports, studies and records, proprietary rights, intellectual property, licenses, permits, rights under or pursuant to all warranties, representations and guarantees, cash, accounts receivable, deposits and prepaid expenses.

“Bankruptcy” of a Person means the occurrence of any of the following events: (i) the filing by such Person of a voluntary case or the seeking of relief under any chapter of Title 11 of the United States Bankruptcy Code, as now constituted or hereafter amended (the “Bankruptcy Code”), (ii) the making by such Person of a general assignment for the benefit of its creditors, (iii) the admission in writing by such Person of its inability to pay its debts as they mature, (iv) the filing by such Person of an application for, or consent to, the appointment of any receiver or a permanent or interim trustee of such Person or of all or any portion of its property, including the appointment or authorization of a trustee, receiver or agent under applicable law or under a contract to take charge of its property for the purposes of enforcing a lien against such property or for the purpose of general administration of such property for the benefit of its creditors, (v) the filing by such Person of a petition seeking a reorganization of its financial affairs or to take advantage of any bankruptcy, reorganization, insolvency, readjustment of debt, dissolution or liquidation law or statute, or an answer admitting the material allegations of a petition filed against it in any proceeding under any such law or statute, (vi) an involuntary case is commenced against such Person by the filing of a petition under any chapter of Title 11 of the Bankruptcy Code and within 60 days after the filing thereof either the petition is not dismissed or the order for relief is not stayed or dismissed, (vii) an order, judgment or decree is entered appointing a receiver or a permanent or interim trustee of such Person or of all or any portion of its property, including the entry of an order, judgment or decree appointing or authorizing a trustee, receiver or agent to take charge of the property of such Person for the purpose of enforcing a lien against such property or for the purpose of general administration of such property for the benefit of the creditors of such Person, and such order, judgment or decree shall continue unstayed and in effect for a period of 60 days, or (viii) an order, judgment or decree is entered, without the approval or consent of such Person, approving or authorizing the reorganization, insolvency, readjustment of debt, dissolution or liquidation of such Person under any such law or statute, and such order, judgment or decree shall continue unstayed and in effect for a period of 60 days. The foregoing definition of “Bankruptcy” is intended to replace and shall supersede the definition of “Bankruptcy” set forth in Sections 18-101(1) and 18-304 of the Act.

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“Base Case Model” means a financial model agreed to by the Members and separately identified as the file named “EXT Opal Geo LLC P50 FINAL 12.16.2016.xlsb”, as attached to the email transmitted by Dave Stoppel to Nachman Isaac and Nir Yahav on December 16, 2016.

“Business Day” means any day other than Saturday, Sunday and any day that is a legal holiday or a day on which banking institutions in New York, New York are authorized by law or governmental action to close.

“Buyout Notice” has the meaning given to such term in Section 9.7(a).

“Capex Contribution” has the meaning given to such term in Section 4.4.

“Capital Account” has the meaning set forth in Section 4.2(a) and as the amounts are adjusted from time to time.

“Capital Contribution” means, with respect to any Member, any amount of money and the initial Gross Asset Value of any property contributed to the Company with respect to the Membership Interests in the Company held or purchased by such Member.

“Capital Interest” means, with respect to any Member, at any time, as the context may require, (i) the balance of such Member’s Capital Account, determined in accordance with Section 4.2 of this Agreement, at such time and (ii) the amount, expressed as a percentage, equal to the fraction the numerator of which is the balance referred to in clause (i) at such time and the denominator of which is the aggregate Capital Account balances of all Members at such time.

“Cash Difference” shall have the meaning set forth in Section 7.11(e)(i).

“Cash Trigger Amount” shall have the meaning set forth in Section 7.11(d)(i).

“Cause” means (A) fraud, willful misappropriation of funds, gross negligence, willful misconduct or a willful violation of a material provision of this Agreement applicable to the Managing Member or Tax Matters Partner, or any Affiliate of any of them, which violation applicable to the Managing Member or Tax Matters Partner, or any Affiliate of any of them, (x) continues unremedied for 30 days after Notice of such violation is given to the Managing Member or Tax Matters Partner, as applicable, and (y) has a material adverse effect on (1) the business, Assets, liabilities, financial condition or results of operations of the Company and its Subsidiaries, taken as a whole or (2) the rights, remedies or economic benefits of the Class B Members under this Agreement, and (z) is not the result of mere negligence, oversight, misunderstanding or misinterpretation of this Agreement (or any applicable law referred to in this Agreement) on the part of the Managing Member or Tax Matters Partner, or (B) breach or default by the Sponsor under the terms of the Sponsor Guaranty with respect to the obligations of the Managing Member or Tax Matters Partner, or any Affiliate of any of them, guaranteed thereunder and the expiration of any applicable cure period thereunder.

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“Certificate of Formation” has the meaning set forth in the preliminary statements of this Agreement.

“Change in Tax Law” means (a) any change in or amendment to the Code or another applicable federal income tax statute, (b) any change in, or issuance of, or promulgation of any temporary or final Treasury Regulations promulgated thereunder that results in any change to the interpretation of the Code or existing Treasury Regulations, (c) any IRS guidance published or to be published in the Internal Revenue Bulletin and / or Cumulative Bulletin, notice, announcement, revenue ruling, revenue procedure, technical advice memorandum, examination directive or similar authority issued by the IRS Large Business and International division, including any revision or amendment to any published IRS guidance, and any published advice, advisory, or legal memorandum issued by IRS Chief Counsel, that applies, advances or articulates a new or different interpretation or analysis of any provision of the Code, any other applicable federal tax statute, any temporary or final Treasury Regulations promulgated thereunder, or any proposed Treasury Regulation promulgated thereunder if the interpretation or analysis of such proposed Treasury Regulation would apply prior to the issuance of the related final Treasury Regulation; or (d) any change in the interpretation of any of the Code or Treasury Regulations by a decision of the U.S. Tax Court, the U.S. Court of Federal Claims, a U.S. District Court, a U.S. Court of Appeals or the U.S. Supreme Court, that applies, advances or articulates a new or different interpretation or analysis of federal income tax law, in each case which is enacted, promulgated or issued, as applicable, subsequent to the Effective Date, that affects negatively in a material manner the federal income tax consequences, including the ability to use any federal income tax benefits, as set forth in the Base Case Model.

“Claim” means any Direct Claim, Third Party Claim or Third Party Penalty Claim.

“Class A Adjusted Deficit Capital Account Balance” has the meaning set forth in Section 10.3(c).

“Class A Approved Transferee” means a Person (or a direct or indirect subsidiary of such Person) that (i) has a tangible net worth of at least five hundred million dollars ($500,000,000) and (ii) either (x) owns and manages or (y) operates (in each case before giving effect to any Transfer hereunder) not less than 250 MW of geothermal projects in the United States, and such Person must have done so for a period of at least five years prior to any Transfer hereunder.

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“Class A Member” means a Member holding one or more Class A Membership Interests.

“Class A Member’s DRO Amount” has the meaning set forth in Section 10.3(c).

“Class A Membership Interests” has the meaning set forth in Section 3.1 of this Agreement.

“Class B Member Loan” has the meaning set forth in Section 4.7(a).

“Class B Contribution Default” has the meaning set forth in Section 4.3(c).

“Class B Member” means a Member holding one or more Class B Membership Interests.

“Class B Member Indemnified Costs” means, subject to Article IX of this Agreement, any and all damages, losses, claims, liabilities, demands, charges, suits, Taxes, penalties, interest, costs, and reasonable expenses (including court costs and reasonable attorneys’ fees and expenses), incurred by any of the Class B Member Indemnified Parties resulting from or relating to (A) any breach or default by the Class A Member of any representation, warranty, covenant, indemnity or agreement under this Agreement or any other Transaction Document, including (i) in its capacity as the Managing Member under this Agreement and (ii) in its capacity as Tax Matters Partner under this Agreement or (B) any claim for fraud, gross negligence, or willful misconduct relating to this Agreement or any Transaction Document.

“Class B Member Indemnified Parties” means the Class B Member and its respective Affiliates and each of their respective shareholders, members, officers, directors, employees, agents, and other representatives, and their respective successors and assigns.

“Class B Membership Interests” has the meaning set forth in Section 3.1 of this Agreement.

“Closing Date Appraisal” has the meaning set forth in the Contribution Agreement.

“Closing Date” has the meaning set forth in the Contribution Agreement.

“Code” means the United States Internal Revenue Code of 1986, as amended from time to time.

“Company” has the meaning set forth in the introductory paragraph hereof.

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“Company Minimum Gain” means the amount of minimum gain there is in connection with nonrecourse liabilities of the Company, calculated in the manner described in Treasury Regulation Sections 1.704-2(b)(2) and 1.704-2(d).

“Competitor” means any Person which, directly or indirectly, through one or more Subsidiaries, Affiliates or joint ventures, operates, manages, or develops or manufactures equipment for use in geothermal power generating facilities or recovered energy (waste heat) based power generating facilities; provided, that any institution that has a passive interest in a geothermal power generating facility similar to that owned by the holders of Class B Membership Interests hereunder shall not be considered a Competitor solely as a result thereof.

“Confidential Information” has the meaning set forth in Section 13.12.

“Consistent Return” has the meaning set forth in Section 7.6(b).

“Consultation” means to confer with, and reasonably consider and take into account the reasonable suggestions, comments or opinions of another Person.

“Contribution Agreement” has the meaning set forth in the preliminary statements of this Agreement.

“Curative Flip Allocation” shall have the meaning set forth in Section 7.11(f).

“Deferred Contribution” means a Capital Contribution made by a Class B Member pursuant to Section 4.3(a).

“Deferred Contribution Cap” means $30,000,000.

“Deferred Contribution Date” means, for each Deferred Contribution Period, January 31 of the following calendar year; provided, however, that if the Class B Member cannot make a determination of the amount of the Capital Contribution it is required to make on the Deferred Contribution Date because the Production Report has not been delivered to the Class B Member pursuant to Section 7.1(f) or a good faith dispute pursuant to Section 7.1(g) or 13.11(b) is ongoing, then such Deferred Contribution Date shall be the date the Class B Member actually makes its Capital Contribution.

“Deferred Contribution Payment Rate” means, for a given Deferred Contribution Period, the payment rate of twenty-three dollars ($23) for each MWh of Excess Production as adjusted annually for inflation consistent with the adjustment to PTCs under Section 45(b)(2) of the Code for each Deferred Contribution Period after 2016 and otherwise subject to the terms of Section 4.3(a), provided, however, that in the event of either (i) a phase out of PTCs under Section 45(b)(1) of the Code, or (ii) a PTC Change in Tax Law, the Deferred Contribution Payment Rate shall be adjusted to the maximum extent necessary to preserve the expected Flip Date under the most recent Tracking Model prior to such phase out or PTC Change in Tax Law, and provided, further, however, in the event any Project is not a qualified facility within the meaning of Section 45(d)(1) of the Code, including without limitation as a result of a PTC Change in Tax Law or a final determination by the IRS or a court (after final adjudication of any contest or appeal), the Deferred Contribution Payment Rate shall be zero with respect to all energy produced by such Project.

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“Deferred Contribution Period” means the period beginning on January 1, 2017 and ending on December 31, 2017, and each calendar year thereafter through December 31, 2022.

“Depreciation” means for each Tax Year or part thereof, an amount equal to the depreciation, amortization, or other cost recovery deduction allowable for United States federal income tax purposes with respect to an Asset for such Tax Year or part thereof, except that if the Gross Asset Value of an Asset differs from its adjusted basis for United States federal income tax purposes at the beginning of such Tax Year, the depreciation, amortization, or other cost recovery deduction for such Tax Year or part thereof shall be an amount which bears the same ratio to such Gross Asset Value as the United States federal income tax depreciation, amortization, or other cost recovery deduction for such Tax Year or part thereof bears to such adjusted tax basis. If such Asset has a zero adjusted tax basis, the depreciation, amortization, or other cost recovery deduction for each Tax Year shall be determined under a method reasonably selected by the Managing Member and agreed to by Members representing a Super-Majority Vote.

“Designated Transfer” has the meaning set forth in Section 9.8.

“Direct Claim” has the meaning set forth in Section 11.2.

“Distributable Cash” means, as of any date, all cash, cash equivalents and liquid investments held by the Company as of such date less all reserves that, in the reasonable judgment of the Managing Member, are necessary or appropriate for the operation of the Company, the Subject Companies or the Projects consistently with the Prudent Operator Standard. Reasonable reserves shall consist of (a) any combination of the following reserves as reasonably determined by the Managing Member: (i) necessary for payment of expenses included in the annual budget, (ii) necessary to prevent or mitigate an emergency situation, (iii) established with the prior written consent of the Members (by Super-Majority Vote), (iv) necessary to allow the Company and the Subject Companies to meet expenses that are clearly identified and expected with reasonable certainty to become due, but that are not included in the budget, (v) necessary to ensure sufficient spare parts or the payment of operational and maintenance costs for each of the Projects, (vi) necessary to service any Existing Indebtedness or other indebtedness (the incurrence of which constituted a Major Decision) incurred by the Subject Companies, (vii) necessary for well drillings or well maintenance or (viii) one or more additional reserves not referred to in the preceding clauses of this definition of “Distributable Cash” that do not in the aggregate exceed five hundred thousand dollars ($500,000) and (b) unless the Class B Member is entitled to one hundred percent (100%) of the Distributable Cash pursuant to clause (ii) of, or the proviso at the end of, Section 6.1(a), in the event that any reserve amount or letter of credit or other security has been drawn upon under any Loan Document (as defined in the OFC2 Note Purchase Agreement) and, as a result, is required to be replenished, an amount equal to such replenishment amount.

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“Distribution Date” means, each Deferred Contribution Date and the last Business Day of each month.

“DRO Amount” equals zero dollars ($0).

“DRO Notice” has the meaning set forth in Section 10.3(b).

“ECA” means the Equity Contribution Agreement dated as of December 16, 2016 among the Class A Member, the Class B Member and Ormat.

“Effective Date” has the meaning set forth in the introductory paragraph hereof.

“Encumbrance” means any charge, claim, community property interest, condition, equitable interest, lien, option, pledge, mortgage, security interest, right of first refusal or restriction of any kind, including any restriction on use, voting, transfer, receipt of income or exercise of any other attribute of ownership.

“Estimated Tax Payment Date” shall have the meaning set forth in Section 7.11(c)(iii)(C).

“Estimated Tax Payment Period” shall mean the periods, within a taxable year, between the Estimated Tax Payment Dates.

“Excepted Non-Conforming Return” has the meaning set forth in Section 7.6(b).

“Excess Production” means, with respect to any Deferred Contribution Period, the excess of the Production eligible for PTCs generated by the PTC Eligible Projects for which the related item of gross income is actually allocated to the Class B Member (without regard to the Fixed Tax Assumptions) through the expiration of the Deferred Contribution Period over the Production Threshold through the expiration of the Deferred Contribution Period as set forth in Schedule 4.3(b).

“Existing Indebtedness” means the aggregate existing indebtedness outstanding under the Senior Notes.

“Fair Market Value” means, with respect to any Asset, the price at which the Asset would change hands between a willing buyer and a willing seller, neither being under any compulsion to buy or to sell, and both having reasonable knowledge of the relevant facts.

“Fiscal Year” has the meaning set forth in Section 7.9.

“Fixed Tax Assumptions” means the following assumptions: (i) the Company is a partnership and each of the Subject Companies is a disregarded entity for federal income tax purposes; (ii) the Class A Member and the Class B Member are the sole partners in the Company for federal income tax purposes; (iii) the Company is the owner for federal income tax purposes of the Projects; ; and (iv) the allocations of tax items (i.e., income gain, loss and deduction, but for the avoidance of doubt, not including depletion) by the Company to the Members, in each case, will be respected by the IRS either because they have “substantial economic effect” or are otherwise consistent with the Members’ interests in the Company within the meaning of Section 704(b) of the Code; provided, this assumption shall not apply to (A) the calculation of items of income, gain, loss, deduction, and credit, and (B) the timing that such items arise and occur.

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“Flip Date” means the later of (i) the Target Flip Date and (ii) the last day of the month in which the Class B Member has achieved an Internal Rate of Return equal to or greater than the Target Internal Rate of Return.

“Flip Exercise Notice,” “Flip Purchase Option” and “Flip Purchase Price” have the meanings set forth in Section 9.6.

“Fundamental Decisions” means the decisions pursuant to clauses (a), (b), (d), (f), (g), (h), (k), (l), (m), (n), (p), (q), (r), (t), (u) and (v) of the definition of Major Decisions.

“GAAP” means United States generally accepted accounting principles as in effect from time to time, consistently applied throughout the specified period.

“Global Financial Services Firm” has the meaning set forth in Section 13.12(a).

“Governmental Body” means the federal government of the United States, any state of the United States or political subdivision thereof, and any entity exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to government and any other governmental entity, instrumentality, agency, authority, commission or self-regulatory organization.

“Gross Asset Value” means, with respect to any Asset, the Asset’s adjusted tax basis for federal income tax purposes, except as follows:

(a)     the initial Gross Asset Value of any Asset contributed by a Member to the Company shall be the Gross Fair Market Value of such Asset as of the date of contribution; provided, that the initial Gross Asset Values of the Assets contributed to the Company pursuant to Section 4.2(d) shall be as set forth in Schedule 4.2(d);

(b)     the Gross Asset Values of all Company Assets shall be adjusted to equal their respective fair market values as of the following times: (i) the acquisition of additional Membership Interests in the Company by any new or existing Member in exchange for more than a de minimis Capital Contribution; (ii) the distribution by the Company to a Member of more than a de minimis amount of money or Company property as consideration for Membership Interests in the Company; and (iii) the liquidation of the Company within the meaning of Treasury Regulation Section 1.704-1(b)(2)(ii)(g); provided, however, that adjustments pursuant to clauses (i) and (ii) shall be made only if the Managing Member reasonably determines, after Consultation with the Members, that such adjustments are necessary or appropriate to reflect the relative economic interests of the Members in the Company;

(c)     the Gross Asset Value of any item of Company Assets distributed to any Member shall be adjusted to equal the Gross Fair Market Value of such Asset on the date of distribution;

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(d)     the Gross Asset Values of all Company Assets shall be adjusted to reflect any adjustments to the adjusted basis of such Assets pursuant to Sections 734(b) or 743(b) of the Code, but only to the extent that such adjustments are required to be taken into account in determining Capital Accounts pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m); provided, however, that Gross Asset Values shall not be adjusted pursuant to this subsection (d) to the extent that the Managing Member determines that an adjustment pursuant to subsection (b) is necessary or appropriate in connection with a transaction that would otherwise result in an adjustment pursuant to this subsection (d); and

(e)     if the Gross Asset Value of an Asset has been determined or adjusted pursuant to subsection (a), (b) or (d) above, such Gross Asset Value shall thereafter be adjusted by the Depreciation taken into account with respect to such Asset.

“Gross Fair Market Value” means, with respect to any Asset, the fair market value of the Asset as reasonably determined by the Managing Member and agreed to by Members representing a Super-Majority Vote.

“Grossed-Up PTC Amount” means an amount equal to the PTC Amount divided by 1 minus the Highest Marginal Rate.

“Guaranty Fee” has the meaning set forth in Section 13.16(b).

“Highest Marginal Rate” means, with respect to the Class B Member, the then highest marginal federal income tax rate generally applicable to entities having the same classification for U.S. income tax purposes as the Class B Member (and not the effective rate of any particular taxpayer), as in effect from time to time; provided, that the Class B Membership Interests shall be treated as continuously held by the original Class B Member in respect of such Class B Membership Interests for purposes of determining the highest marginal federal income tax rate generally applicable to any holder of such Class B Membership Interests.

“Indemnified Parties” has the meaning set forth in Section 11.1.

“Indemnifying Party” has the meaning set forth in Section 11.1.

“Independent Accounting Firm” means PricewaterhouseCoopers, or an accounting firm which is otherwise mutually acceptable to the Class A Member and the Class B Member.

“Independent Engineer” has the meaning set forth in the Contribution Agreement.

“Insurance Consultant” has the meaning set forth in the Contribution Agreement.

“Intermediate Company” has the meaning set forth in the preliminary statements of this Agreement.

“Internal Rate of Return” means the annual effective discount rate computed in a manner consistent with the rules and conventions described in Section 7.11 (including by taking into account the Cash Flows set forth in Section 7.11(c)(ii)) and calculated using the “XIRR” function on Microsoft Office Excel 2010 (or the same function in any subsequent version of Microsoft Office Excel).

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“IRS” means the Internal Revenue Service or any successor agency thereto.

“JPM” has the meaning set forth in the introductory paragraph hereof.

“Known Project Geothermal Resource Area” has the meaning set forth in Section 12.1(a).

“Legal Requirement” means, as to any Person (as defined in the Contribution Agreement), any requirement under any law, statute, act, decree, ordinance, rule, directive, permit, order, treaty, code or regulation (including any of the foregoing relating to health or safety matters or any Environmental Law (as such term is defined in the Contribution Agreement)), as enacted, issued or promulgated by any Governmental Body, including all amendments, modifications, extensions, replacements or re-enactments thereof, to the extent that any of the foregoing has the force of law.

“Major Decisions” means any of the following:

(a)     Any sale, lease or other voluntary disposition of any limited liability company interest in the Company or any Subject Company;

(b)     Any sale, lease or other voluntary disposition of all or substantially all of the Assets of any Subject Company;

(c)     Any sale, lease or other voluntary disposition of any Assets of any Subject Company with an aggregate fair market value in excess of five million dollars ($5,000,000) during any 12 month period, other than in the Ordinary Course of Business;

(d)     Any Encumbrance or grant of any Encumbrance on the Assets or rights of the Company or the Assets and rights of any Subject Company other than Permitted Liens;

(e)     The Company, or any Subject Company (1) cancel, suspend, renew or terminate any Material Contract (2) assign, release or relinquish the rights or obligations of any party to, or amend, any Material Contract if any of the foregoing items in this clause (2) would have a Material Adverse Effect on the Company or any such Subject Company, or (3) renew any Material Contract except to the extent such renewal is on substantially the same terms as the original Material Contract, provided that none of such actions will be considered a Major Decision if the actions are required by or resulting from any requirement of any Governmental Body.

(f)     The Company or any Subject Company takes or files any action or institute any proceedings in Bankruptcy;

(g)     Any merger or consolidation of the Company or any Subject Company, other than any merger of one Subject Company with another Subject Company;

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(h)     Any incurrence or guarantee of indebtedness for borrowed money or capitalized lease obligations in excess of (x) four million dollars ($4,000,000), in the aggregate, for the Company, and (y) three million dollars ($3,000,000), for any Subject Company, other than Working Capital Loans;

(i)     Any issuance or redemption by the Company of any Membership Interests or other equity interest of any kind in the Company;

(j)     Approval of any transactions (other than Working Capital Loans and other transactions contemplated by any of the Transaction Documents, including under clause (q) of this definition) between the Company or any Subject Company, as the case may be, and any member thereof or any Affiliates thereof;

(k)     Any settlement of claims, litigation or arbitration if, as a result of such settlement, (x) the Company would be obligated to pay more than $4 million, in the aggregate, (y) the Intermediate Company would be obligated to pay more than $3 million, in the aggregate or (z) any individual Project Owner would be obligated to pay more than $2 million, in the aggregate;

(l)     Any action that would cause the Company or any Subject Company to engage in any business or activity that is not within the purpose of such entity, as set forth in such entity’s Organizational Documents, or to change such purpose, or to the extent that there would be an elective change to any Subject Company’s status as a Qualifying Facility or any action that would be inconsistent with the status of a Subject Company’s status as a Qualifying Facility (other than as a result of a change in law providing for a successor status for similar projects) if, in each case, such action or change would result in the Class B Member no longer being eligible for an exemption under PUHCA.

(m)     Any amendment or cancellation of (i) the certificate of formation of the Company or any Project Company or (ii) of any Transaction Document; provided, however, solely with respect to any O&M Agreement, only material amendments of such O&M Agreement shall be considered a Major Decision;

(n)     The admission of any additional member in the Company, other than pursuant to terms of this Agreement or in connection with the exercise of rights by any lenders to OrLeaf to which OrLeaf has pledged its Membership Interests to secure a borrowing by OrLeaf; provided such lenders are an Approved Transferee;

(o)     Any consent, approval or waiver that would allow the expenditure by any Subject Company under an operation and maintenance agreement for a Project, which spending is either (x) not contemplated in an Annual Budget or (y) exceeds by more than the greater of (A) one million dollars ($1,000,000) and (B) ten percent (10%) of the amounts contemplated in an Annual Budget; provided that none of such actions will be considered a Major Decision if the actions relate to expenditures in connection with any expansion capital expenditures for any Project, unless (1) the Class B Members elect to, and the Members agree on, the Class B Members’ funding contributions for such capital expenditure or (2) such expansion has a material adverse effect on the Class B Member, the Company or any Subject Company;

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(p)     Entering into any contract under which (x) the Company would be obligated to pay more than four million dollars ($4,000,000), in the aggregate, in any Fiscal Year, (y) any Subject Company would be obligated to pay more than three million dollars ($3,000,000), in the aggregate, in any Fiscal Year, in each case other than (1) Working Capital Loans or (2) as contemplated in an Annual Budget;

(q)     Entering into any contract with any Affiliate of a Member that would require payments by the Company or any Subject Company of more than four million dollars ($4,000,000), in the aggregate, in any Fiscal Year, other than (a) contracts providing for Working Capital Loans, (b) the Transaction Documents or (c) an extension or replacement of an agreement described in the foregoing (a) or (b) with the same or another Affiliate of such Member;

(r)     The Company or any Subject Company hire any employees;

(s)     Approval of renegotiations of the operations and maintenance fee under the relevant O&M Agreement to the extent taking place every five years as provided under such O&M Agreement, unless the increase is solely to adjust for inflation;

(t)     Electing that the Company be treated other than as a partnership for United States federal income tax purposes, or causing the Company to receive (or permit to be received) any grants, tax-exempt bonds, subsidized energy financing, or other federal tax credits, each within the meaning of Section 45(b)(3) of the Code;

(u)     Prior to the end of the applicable statute of limitations for the year in which the Flip Date occurs, (i) commencing of a judicial action (including filing a petition as contemplated in Section 6226(a) or Section 6228 of the Code) with respect to a federal income tax matter or appeal any adverse determination of a judicial tribunal; (ii) entering into a settlement agreement with the IRS which purports to bind the Members; (iii) intervening in any action as contemplated by Section 6226(b) of the Code; (iv) filing any request contemplated in Section 6227(b) of the Code; or (v) entering into an agreement extending the period of limitations as contemplated in Section 6229(b)(1)(B) of Code; and

(v)     Any amendment to modify the amortization schedule of the Senior Notes.

“Managing Member” has the meaning set forth in Section 8.1. The Managing Member is the “manager” of the Company within the meaning of the Act.

“Material Adverse Change in Tax Law” means any Change in Tax Law that (x) becomes effective after the Effective Date, (y) directly affects the availability or the rate of PTCs and (z) that would cause the Flip Date projected in the Tracking Model immediately prior to such Change in Tax Law to be delayed by two years or more after taking such Change in Tax Law into effect.

“Material Adverse Effect” has the meaning set forth in the Contribution Agreement.

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“Material Contract” means (1) a contract for the sale of electric energy or transmission services of a Project; (2) a contract for the sale, use or allocation of geothermal fluid, brine or other geothermal elements; (3) a contract, lease, indenture or security under which the Company or any Subject Company (a) has created, incurred, assumed or guaranteed any indebtedness for borrowed money or obligations under any lease that, in accordance with GAAP, should be capitalized, (b) has created a mortgage, security interest or other consensual encumbrance on any property with a fair market value in excess of five million dollars ($5,000,000) (other than any Permitted Liens), or (c) has a reimbursement obligation in respect of any letter of credit, guaranty, bond, or other credit or collateral support arrangement required to be maintained by any Subject Company under the terms of any contract referred to in clause (1) above; (4) a contract for management, operation or maintenance of a Project; (5) a product warranty or repair contract by or with a manufacturer or vendor of equipment owned or leased by a Subject Company with a fair market value in excess of five million dollars ($5,000,000); and (6) any other contract that could require payments of more than five million dollars ($5,000,000), in the aggregate for any Subject Company during any Fiscal Year.

“Member” means any Person executing this Agreement as of the date of this Agreement as a member of the Company or any Person admitted to the Company as a member as provided in this Agreement (each in the capacity as a member of the Company), but does not include any Person who has ceased to be a member of the Company.

“Member Nonrecourse Debt” means “partner nonrecourse debt” as defined in Treasury Regulation Section 1.704-2(b)(4). An example is where a Member or a person related to the Member makes a loan on a nonrecourse basis to the Company.

“Member Nonrecourse Deductions” has the meaning given to the term “partner nonrecourse deductions” in Treasury Regulation Sections 1.704-2(i)(1) and 1.704-2(i)(2).

“Membership Interest” means the limited liability company interest of a Member in the Company, including rights to distributions (liquidating or otherwise), allocations, and to vote, consent or approve, if any.

“Minimum Gain Attributable to Member Nonrecourse Debt” means the amount of minimum gain there is in connection with a Member Nonrecourse Debt, calculated in the manner described in Treasury Regulation Section 1.704(i)(3).

“MW” means megawatt.

“MWh” means megawatt hour.

“Non-Conforming Return” has the meaning set forth in Section 7.6(b).

“Nonrecourse Deductions” has the meaning given to such term in Treasury Regulation Sections 1.704-2(b)(1) and 1.704-2(c).

“Nonrecourse Liability” has the meaning given to such term in Treasury Regulation Section 1.704-2(b)(3).

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“Notice” has the meaning set forth in Section 13.1.

“O&M Agreements” mean, collectively, each of the operation and maintenance agreements between the Operator and a Subject Company, as each such agreement may be amended, supplemented or replaced from time to time.

“OFAC Blocked List” means the list of Specially Designated Nationals and Blocked Persons maintained by the Office of Foreign Assets Control, or any replacement list intended to be a successor to such list.

“OFC2 Distribution Block” means the occurrence of any event contemplated in Section 10.5 of the OFC2 Note Purchase Agreement that would result in any Issuer (as defined in the OFC2 Note Purchase Agreement) being prohibited from (i) the making or payment of any distribution or dividend on any membership interest or on any rights with respect to membership interests or (ii) the application of any funds, property or assets to the purchase, redemption, sinking fund or other retirement of, or agreement to purchase or redeem, any membership interest.

“OFC2 Foreclosure” means any exercise of remedies by the Trustee (as defined in the OFC2 Note Purchase Agreement) or Senior Creditors (as defined in the OFC2 Note Purchase Agreement) under the OFC2 Note Purchase Agreement, OFC2 Indenture or any other Loan Document (as defined in the OFC2 Note Purchase Agreement), the result of which is that the Company no longer owns (i) one hundred percent (100%) of the membership interests in the Intermediate Company, (ii) one hundred percent (100%) (directly or indirectly) of the Project Companies owned by the Intermediate Company or (iii) one hundred percent (100%) (directly or indirectly) of the Projects owned (directly or indirectly) by the Intermediate Company.

“OFC2 Indenture” means that certain Indenture of Trust and Security Agreement dated as of September 23, 2011 (as amended, amended and restated, modified and/or supplemented from time to time) among OFC 2 LLC, ORNI 15 LLC, ORNI 39 LLC, ORNI 42 LLC, and HSS II, LLC, and Wilmington Trust Company, as Trustee and as Depository.

“OFC2 Note Purchase Agreement” means that certain Note Purchase Agreement dated as of September 23, 2011 (as amended, amended and restated, modified and/or supplemented from time to time) among OFC 2 LLC, ORNI 15 LLC, ORNI 39 LLC, ORNI 42 LLC, and HSS II, LLC, as the Issuers, OFC 2 Noteholder Trust, as Purchaser, the U.S. Department of Energy, as Guarantor, and John Hancock Life Insurance Company (U.S.A.), as Administrative Agent.

“Offer Notice” has the meaning set forth in Section 9.5(a) of this Agreement.

“Operations Report” has the meaning set forth in Section 7.1 of this Agreement.

“Operator” means Ormat, or any successor thereto, each in its capacity as the operator pursuant to each O&M Agreement.

“Ordinary Course of Business” means the ordinary conduct of business consistent with past custom and practice (including with respect to quantity and frequency).

-15-

“Organizational Documents” means articles of incorporation, certificate of incorporation, charter, bylaws, articles of organization, formation or association, regulations, operating agreement, certificate of limited partnership, partnership agreement, and all other similar documents, instruments or certificates executed, adopted, or filed in connection with the creation, formation or organization of a Person, including any amendments thereto.

“Ormat” means Ormat Nevada, Inc., a Delaware corporation.

“ORNI 37” has the meaning set forth in the Contribution Agreement

“Other Consent Matters” means each of the matters requiring consent, approval, authorization or vote of or by the Class B Member, in each case as and to the extent so required, pursuant to Sections 3.5, 4.7(a), 6.1(d), 6.5, 7.1(b), 7.5(b), 7.7(a), 7.7(c), 9.2(b), 10.1(a), 10.2(a), 10.4, 12.3(e), 12.3(g), and 13.11(a), and the definitions of Accounting Firm, Depreciation, Distributable Cash (clause (iii) only) and Gross Fair Market Value.

“Overpayment” has the meaning set forth in Section 7.1(g)(vi).

“Partnership Representative” means the “partnership representative” as that term is defined in Code Section 6223 of Title XI.

“Permitted Encumbrance” means Encumbrances provided for under the Transaction Documents, liens for Taxes not yet due and payable and restrictions on transfer of the Membership Interests under any applicable federal, state or foreign securities law.

“Permitted Investments” means any of the following having a maturity of not greater than one year from the date of issuance thereof: (a) readily marketable direct obligations of the government of the United States of America or any agency or instrumentality thereof or obligations unconditionally guaranteed by the full faith and credit of the government of the United States of America, (b) insured certificates of deposit of or time deposits with any commercial bank that is a member of the Federal Reserve System, issues (or the parent of which issues) commercial paper rated at least “Prime 1” (or the then equivalent grade) by Moody’s Investors Service, Inc. or “A 1” (or the then equivalent grade) by Standard & Poor’s Corporation, is organized under the laws of the United States or any State thereof and has combined capital and surplus of at least one billion dollars ($1,000,000,000) or (c) money market funds rated “AAA “ or “Aaa2” or better by Standard & Poor’s Corporation or Moody’s Investors Service, Inc.

“Permitted Liens” means (a) liens for taxes not yet due or that are being contested in good faith by appropriate proceedings, (b) carriers’, warehousemen’s, mechanics’, materialmen’s, repairmen’s, employees’, contractors’, operators’ or other similar liens or charges securing the payment of expenses not yet due and payable that were incurred in the Ordinary Course of Business of each Subject Company, (c) trade contracts or other obligations of a like nature incurred in the Ordinary Course of Business of each Subject Company, (d) obligations or duties to any Governmental Body arising in the Ordinary Course of Business (including under licenses and permits held by the Subject Companies and under all Applicable Legal Requirements), (e) obligations or duties under easements, leases or other property rights, (f) Existing Indebtedness and (g) all other encumbrances and exceptions that are incurred in the Ordinary Course of Business of each Project, are not incurred for borrowed money and do not have a material adverse effect on either the use of any Assets of the Subject Companies as currently used or the value of any such Assets.

-16-

“Permitted Transfers” has the meaning set forth in Section 9.4.

“Person” has the meaning set forth in Section 18-101(12) of the Act.

“PPA” has the meaning set forth in the Contribution Agreement.

“Production” means electricity (measured in MWh) actually generated by a Project and sold to a Person that is an Unrelated Party by the applicable Subject Company.

“Production Report” has the meaning set forth in Section 7.1(f).

“Production Threshold” means, for each Deferred Contribution Period, MWhs as set forth in Schedule 4.3(b) under the heading “Production Threshold”, provided, however, that in the event of either (i) a phase out of PTCs under Section 45(b)(1) of the Code, or (ii) a PTC Change in Tax Law, the Production Threshold shall be adjusted to the maximum extent necessary to preserve the expected Flip Date under the most recent Tracking Model prior to such phase out (for the avoidance of doubt, after taking into account any corresponding adjustment to the Deferred Contribution Payment Rate as a result of such change). For the avoidance of doubt, in the event that the PTC rate as provided by any guidance or publication issued by the IRS pursuant to Code Section 45(e)(2)(A) is different from the PTC rate assumed in the Base Case Model in any year, the applicable Production Threshold for such year shall be equal to the product of the Production Threshold as set forth in Schedule 4.3(b) applicable to such year multiplied by a factor, the numerator of which is the PTC rate assumed in the Base Case Model and the denominator of which is the PTC rate as provided by the guidance or publication issued by the IRS pursuant to Code Section 45(e)(2)(A). For the avoidance of doubt, after the Flip Date occurs, the Production Threshold will be zero.

“Prohibited Person” means any Person that is (a) listed on, or owned or controlled by a Person listed on, or acting on behalf of a Person listed on, the OFAC Blocked List, (b) a Sanctioned Person, (c) otherwise a target of Sanctions (“target of Sanctions” signifying a Person with whom a Person or other national of a Governmental Authority that administers Sanctions would be prohibited or restricted by law from engaging in trade, business or other activities), or (d) any party that to the best knowledge and reasonable belief of the Class A Member is known to directly or indirectly (i) make or to have made any illicit bribes or otherwise engaged in corrupt behavior in violation of Anti-Corruption Laws or (ii) to have acted in connection with the illegal laundering of the proceeds of any criminal activity.

“Projects” has the meaning set forth in the preliminary statements of this Agreement.

“Project Companies” has the meaning set forth in the preliminary statements of this Agreement.

-17-

“Prudent Operator Standard” means that a Person will (a) perform its duties in good faith and as a reasonably prudent operator, (b) perform its duties in compliance with (or to cause the applicable Subject Companies to comply in all materials respects with) the requirements of the Material Contracts, (c) exercise such care, skill and diligence as a reasonably prudent business company of established reputation engaged in the geothermal energy business would exercise in the conduct of its business and for the advancement or protection of its own interests, (d) perform the duties in accordance with applicable geothermal energy industry standards, taking into account, prior to the Flip Date, the requirements to maintain qualification for PTCs, (e) use sufficient and properly trained and skilled personnel, and (f) use parts and supplies that meet the specifications set forth in the Material Contracts, in all cases with respect to (a) through (f) herein, taking into account all of the costs, expenses and benefits of operation of each Project.

“PTCs” means the tax credits pursuant to Section 45 of the Code (or any successor to such Code section) for the sale of electricity produced from certain renewable resources.

“PTC Amount” means the PTCs actually generated and allocated to the Class B Member.

“PTC Change in Tax Law” means any Change in Tax Law that limits, restricts, defers or disallows the ability of the Company to claim PTCs.

“PTC Eligible Projects” has the meaning set forth in the Contribution Agreement.

“PUHCA” means the Public Utility Holding Company Act of 2005 and FERC’s regulations promulgated thereunder.

“Qualifying Facility” means a qualifying small power production facility pursuant to the Public Utility Regulatory Policies Act of 1978, as amended, and FERC’s regulations thereunder at 18 C.F.R. § 292.203.

“Quarter” means, with respect to the Fiscal Year of the Company, each of the three month periods from January 1 through March 31, from April 1 through June 30, from July 1 through September 30 and from October 1 through December 31 of any calendar year.

“Recapture Gain” has the meaning set forth in Section 5.3(c).

“Regulated Holder” means any holder of the Company’s securities that is (or that is a subsidiary of a bank holding company that is) subject to the various provisions of Regulation Y of the Board of Governors of the Federal Reserve Systems, 12 C.F.R. Part 225 (or any successor to Regulation Y).

“Regulatory Problem” means, with respect to the Class B Member, (a) any set of facts or circumstances wherein it has been asserted by any Governmental Authority (or such Class B Member reasonably believes based on advice of its counsel or regulators that there is a material risk of such assertion) that such Class B Member (or any bank holding company or other regulated bank entity that controls such Class B Member) is not entitled to hold, or exercise any material right with respect to, all or any portion of the Membership Interest which such Person holds or (b) any set of facts or circumstances where such Person and its Affiliates does or would own, control or have power (including voting rights) over a greater quantity of the Membership Interests than is permitted under any law applicable to such Person or to which such Person is subject

-18-

“Representatives” means, with respect to any Person, the managing member(s), the officers, directors, employees, representatives or agents (including investment bankers, financial advisors, attorneys, accountants, brokers and other advisors) of such Person, to the extent that such officer, director, employee, representative or agent of such Person is acting in his or her capacity as an officer, director, employee, representative or agent of such Person.

“Revenue Procedures” means statements of procedure from the IRS designated as such and issued to the general public, affecting the rights or duties of taxpayers or other members of the public under the Code.

“ROFO Offer” has the meaning set forth in Section 9.5(b) of this Agreement.

“Sanctioned Country” has the meaning given to such term in the Contribution Agreement.

“Sanctioned Person” has the meaning given to such term in the Contribution Agreement.

“Sanctions” has the meaning given to such term in the Contribution Agreement.

“Senior Notes” means the senior notes issued under the OFC2 Note Purchase Agreement.

“Sponsor” means Ormat Technologies, Inc., a Delaware corporation.

“Sponsor Guaranty” means the Guaranty Agreement made by the Sponsor for the benefit of JPM.

“Steam Resource” has the meaning set forth in the Contribution Agreement.

“Subject Companies” has the meaning set forth in the preliminary statements of this Agreement.

“Subsidiary” means, with respect to any Person, any corporation, partnership, limited liability company, joint venture or other entity of which such Person (either alone or through or together with any other Person pursuant to any agreement, arrangement, contract or other commitment) owns, directly or indirectly, fifty percent (50%) or more of the stock or other equity interests the holders of which are generally entitled to vote for the election of the board of directors or other governing body of such corporation or other legal entity.

“Super-Majority Vote” has the meaning set forth in Section 3.2.

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“Target Flip Date” means December 31, 2022.

“Target Internal Rate of Return” means an Internal Rate of Return of twenty percent (20%).

“Target IRR Notice” has the meaning set forth in Section 7.1(e).

“Target IRR Report” has the meaning set forth in Section 7.1(d).

“Tax” (and, with correlative meaning, “Taxes” and “Taxable”) means:

(i)     any taxes, customs, duties, charges, fees, levies, penalties or other assessments imposed by any federal, state, local or foreign taxing authority, including, but not limited to, income, gross receipts, windfall profit, severance, property, production, sales, use, license, excise, franchise, net worth, employment, occupation, payroll, withholding, social security, alternative or add-on minimum, ad valorem, transfer, stamp, or environmental tax, or any other tax, custom, duty, fee, levy or other like assessment or charge of any kind whatsoever, together with any interest, penalty, addition to tax, or additional amount attributable thereto; and

(ii)     any liability for the payment of amounts with respect to payment of a type described in clause (i), including as a result of being a member of an affiliated, consolidated, combined or unitary group, as a result of succeeding to such liability as a result of merger, conversion or Asset transfer or as a result of any obligation under any tax sharing arrangement or tax indemnity agreement.

“Tax Matters Partner” has the meaning set forth in Section 7.7(a).

“Tax Return” has the meaning set forth in Section 7.6(b).

“Tax Year” has the meaning set forth in Section 7.10.

“Termination Date” has the meaning set forth in Section 2.4.

“Third Party Claim” has the meaning set forth in Section 11.3.

“Third Party Penalty Claim” has the meaning set forth in Section 11.3.

“Title XI” has the meaning set forth in Section 7.7(f).

“Tracking Model” means the Base Case Model, as adjusted from time to time to account for actual performance except as provided in Section 7.11.

“Transaction Documents” means this Agreement, the Contribution Agreement, the Sponsor Guaranty, the O&M Agreements and each of the other documents required to be delivered on the Closing Date, individually and collectively.

“Transfer” has the meaning set forth in Section 9.1.

“Treasury Regulations” means the regulations promulgated under the Code, as such regulations are in effect on the date hereof or as otherwise contemplated by Section 5.2.

-20-

“Trigger Percentage” shall have the meaning set forth in Section 7.11(d)(i).

“UCC” means the Uniform Commercial Code of any applicable jurisdiction.

“Underpayment” has the meaning set forth in Section 7.1(g)(v).

“Unrelated Persons” means a Person that is not “related”, within the meaning of Section 45(e)(4) of Code, to any Person to whom any of the Subject Companies sells electricity during the period the Company is entitled to PTCs on such electricity.

“Working Capital Loan” has the meaning given to such term in Section 4.5.

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EX-10.1.15

Exhibit 10.1.15

EQUITY CONTRIBUTION AGREEMENT

with respect to

OPAL GEO LLC

by and among

Ormat Nevada Inc.,

ORLEAF LLC

and

JPM CAPITAL CORPORATION

Table of Contents

		Page
Article I DEFINITIONS		1
Section 1.1	Defined Terms	1
Section 1.2	Other Definitional Provisions	10
Article II CAPITAL CONTRIBUTIONS; MEMBERSHIP INTERESTS		11
Section 2.1	Issuance of Class B Membership Interests	11
Section 2.2	Use of Proceeds	11
Section 2.3	Tax Treatment	11
Section 2.4	Closing	12
Section 2.5	Conditions Precedent to the Obligations of JPM in Connection with the Closing	12
Section 2.6	Conditions Precedent to the Obligations of the Sellers in Connection with the Closing	15
Article III REPRESENTATIONS AND WARRANTIES OF THE SELLERS		16
Section 3.1	Organization, Good Standing, Etc. of ONI and OrLeaf	16
Section 3.2	Organization, Good Standing, Etc. of the Company and Subject Companies	17
Section 3.3	Authority	17
Section 3.4	No Conflicts	17
Section 3.5	Absence of Litigation	18
Section 3.6	Ownership	18
Section 3.7	Sufficiency of Assets	18
Section 3.8	Valid Interests	19
Section 3.9	Tax Matters	19
Section 3.10	Balance Sheets, Financial Statements and Operating Reports	22
Section 3.11	Absence of Material Change	23
Section 3.12	Compliance with Applicable Law	23
Section 3.13	Environmental Matters	24
Section 3.14	Licenses and Permits	24
Section 3.15	Insurance	25
Section 3.16	Real Property	25
Section 3.17	Personal Property	26
Section 3.18	Liens	26
Section 3.19	Material Contracts	26
Section 3.20	Consents and Approvals	26
Section 3.21	Employee Matters	26
Section 3.22	Affiliate Transactions	26
Section 3.23	QF Status	27
Section 3.24	Intellectual Property	27

Section 3.25	Public Utility Holding Company	27
Section 3.26	Investment Company Act	27
Section 3.27	No Condemnation	27
Section 3.28	No Casualty	27
Section 3.29	Brokers	27
Section 3.30	Background Materials	27
Section 3.31	No Other Representations	28
Article IV REPRESENTATIONS AND WARRANTIES OF JPM		28
Section 4.1	Organization, Good Standing, Etc.	28
Section 4.2	Authority	28
Section 4.3	No Conflicts	29
Section 4.4	Absence of Litigation	29
Section 4.5	Information and Due Diligence	29
Section 4.6	Information and Investment Intent	29
Section 4.7	Security Interest	30
Section 4.8	Public Utility Holding Company	30
Section 4.9	No Other Seller Representations	30
Section 4.10	Tax Matters	30
Article V TAX MATTERS		30
Section 5.1	Transfer Taxes	30
Section 5.2	Pre-Closing Date Tax Return Preparation	30
Section 5.3	Tax Periods Beginning Before the Effective Date	31
Section 5.4	Refunds and Tax Benefits; Amended Tax Returns	31
Section 5.5	Cooperation on Tax Matters	32
Article VI CERTAIN OTHER COVENANTS		32
Section 6.1	Confidentiality	32
Section 6.2	Intellectual Property	32
Section 6.3	Licenses and Permits; Material Contract	32
Article VII INDEMNIFICATION		33
Section 7.1	Indemnification	33
Article VIII GENERAL PROVISIONS		33
Section 8.1	Exhibits and Schedules; Headings	33
Section 8.2	Disclosure Schedules	33
Section 8.3	Amendment, Modification and Waiver	33
Section 8.4	Severability	33
Section 8.5	Survival	33
Section 8.6	Expenses	33
Section 8.7	Parties in Interest	33
Section 8.8	Notices	34
Section 8.9	Counterparts	35
Section 8.10	Entire Agreement	35
Section 8.11	Governing Law; Choice of Forum; Waiver of Jury Trial	35
Section 8.12	Attorneys®€™ Fees	36
Section 8.13	Public Announcements	36
Section 8.14	Further Assurances	36
Section 8.15	Assignment	36
Section 8.16	Relationship of Parties; No Strict Construction	36

EXHIBITS

Exhibit A	Company LLC Agreement
Exhibit B	OTEC Guaranty
Exhibit C	ONI Guaranty

SCHEDULES

Schedule 1 Project Companies and Projects

Schedule 2.5(l)	Reports
Schedule 2.5(t)	Post-Closing Consents of JPM
Schedule 2.5(v)	Title and Survey Requirements
Schedule 3.2	Organizational Documents
Schedule 3.4	Ormat Governmental Consents and Approvals
Schedule 3.5	Absence of Litigation
Schedule 3.6	Organizational Matters
Schedule 3.7	Sufficiency of Assets
Schedule 3.9(c)	Rights to Acquire Ownership
Schedule 3.9(f)	PTC Start and Placed in Service Dates
Schedule 3.9(m)	Grant Applicants
Schedule 3.9(q)	Powers of Attorney
Schedule 3.9(v)	Tax Conventions
Schedule 3.11	Absence of Material Change
Schedule 3.12	Compliance with Applicable Law
Schedule 3.13	Environmental Matters
Schedule 3.14	Licenses and Permits
Schedule 3.15	Insurance
Schedule 3.16	Real Property
Schedule 3.17	Personal Property
Schedule 3.18	Liens
Schedule 3.19	Material Contracts
Schedule 3.22	Affiliate Transactions
Schedule 4.3	JPM Governmental Consents and Approvals

EQUITY CONTRIBUTION AGREEMENT

This Equity Contribution Agreement (this “Agreement”) is made and entered into as of December 16, 2016 (the “Effective Date”) by and between JPM Capital Corporation, a Delaware corporation (“JPM”), Ormat Nevada Inc., a Delaware corporation (“ONI”), and OrLeaf LLC, a Delaware limited liability company (“OrLeaf”, and together with ONI, the “Sellers”). ONI, OrLeaf, and JPM each a “Party,” and collectively, the “Parties.”

RECITALS

WHEREAS, Opal Geo LLC, a Delaware limited liability company (the “Company”), was formed by the filing of its Certificate of Formation with the Secretary of State of the State of Delaware on November 17, 2016;

WHEREAS, OrLeaf currently owns all of the membership interests in the Company;

WHEREAS, under the terms of OrLeaf's limited liability company agreement, ONI is the managing member of OrLeaf;

WHEREAS, the Company owns one hundred percent (100%) of the limited liability interests in OFC 2 LLC, a Delaware limited liability company (“OFC 2”) and ORNI 37 LLC, a Delaware limited liability company;

WHEREAS, pursuant to the terms and provisions of this Agreement, JPM will make an initial capital contribution to the Company in the amount set forth herein and OrLeaf will cause the Company to issue membership interests in the Company to JPM which interests, upon execution of the Company LLC Agreement, shall be designated as Class B Membership Interests having the rights and preferences set forth in the Company LLC Agreement;

WHEREAS, upon the execution of the Company LLC Agreement the Class B Membership Interests issued to JPM will constitute one hundred percent (100%) of all of the outstanding Class B Membership Interests in the Company;

WHEREAS, OrLeaf will retain one hundred percent (100%) of all of the outstanding Class A Membership Interests in the Company.

NOW, THEREFORE, in consideration of the respective representations, warranties, covenants, agreements, and conditions hereinafter set forth, and other good and valuable consideration, the sufficiency of which is hereby acknowledged, the Parties hereto hereby agree as follows:

Article I 

DEFINITIONS

Section 1.1     Defined Terms. Capitalized terms used but not otherwise defined herein shall have the meanings given as follows:

“Affiliate” means, with respect to any Person, any other Person controlling, controlled by or under common control with such first Person. For purpose of this definition and this Agreement, (a) the term “control” (and correlative terms) means (1) the ownership of fifty percent (50%) or more of the equity interest in a Person, or (2) the power, whether by contract, equity ownership or otherwise, to direct or cause the direction of the policies or management of a Person, and (b) the Company shall be deemed to be an Affiliate of OrLeaf and ONI prior to the Closing (for purposes of representations and warranties), but shall not be deemed to be an Affiliate of OrLeaf, ONI or JPM from and after the Closing.

“Agreement” has the meaning set forth in the introductory paragraph hereof.

“Anti-Corruption Laws” has the meaning set forth in Section 3.12(b)(ii).

“Applicable Law” means any applicable constitution, statute, law, rule, regulation, ordinance, judgment, order, decree or approval of any Governmental Authority, or any published directive or requirement of any Governmental Authority, or other governmental restriction which has the force of law, or any determination by or judgment of any judicial authority applicable to and binding on ONI, OrLeaf, the Company, any Subject Company, or JPM, as the context may require, in effect as of the Closing Date and in each case as amended, modified and/or supplemented, to the extent that any of the foregoing has the force of law.

“Background Materials” means, collectively, all factual information and representations set forth herein or in any Schedule attached hereto with respect to the Projects, including all written materials to which JPM and its advisors and consultants were given electronic access in the Dataroom, and any and all additional written materials provided to JPM and its advisors and consultants in response to diligence inquiries made in connection with the transactions contemplated hereby.

“Base Case Model” has the meaning set forth in the Company LLC Agreement.

“Business Day” means any day other than (i) a Saturday or Sunday or (ii) a day on which commercial banks in New York, New York are authorized or required to be closed.

“Class A Membership Interests” has the meaning set forth in the Company LLC Agreement.

“Class B Member Indemnified Costs” has the meaning set forth in the Company LLC Agreement.

“Class B Member Indemnified Parties” has the meaning set forth in the Company LLC Agreement.

“Class B Membership Interests” has the meaning set forth in the Company LLC Agreement.

“Closing” has the meaning set forth in Section 2.4.

“Closing Date” means the date of the Closing.

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“Code” means the United States Internal Revenue Code of 1986, as amended.

“Company” has the meaning set forth in the Recitals.

“Company LLC Agreement” means the Amended and Restated Limited Liability Company Agreement of the Company, dated as of the Closing Date, attached hereto as Exhibit A.

“Confidentiality Agreement” has the meaning set forth in Section 6.1.

“Consultants” means the third party consultants identified in Schedule 2.5(l).

“Current Balance Sheet” has the meaning set forth in Section 3.10(a).

“DAC 2 Balance Sheet” has the meaning set forth in Section 3.10(b).

“DAC 2 Project” means the approximately 19.4 MW geothermal power project owned by the DAC 2 Project Company as described in Schedule 1.

“DAC 2 Project Company” means the Project Company that owns the DAC 2 Project.

“Dataroom” means the virtual dataroom to which the Sellers have given JPM and its advisors and consultants electronic access in connection with the transactions contemplated by this Agreement.

“Effective Date” has the meaning set forth in the introductory paragraph hereof.

“Effective Time” has the meaning set forth in Section 2.4.

“Environmental Law” means any and all Applicable Laws issued or promulgated by any Governmental Authority, and any permits required thereunder, relating to the protection or preservation of the environment, including the preservation or reclamation of natural resources, human health and safety in respect of exposure to Hazardous Substances, or the management, release or threatened release of Hazardous Substances.

“ERISA” means the United States Employee Retirement Income Security Act of 1974, as amended.

“Exhibits” means the Exhibits attached to this Agreement.

“Existing Indebtedness” means the aggregate existing indebtedness outstanding under the Senior Notes.

“Existing Indebtedness Security Documents” means the OFC 2 Indenture and each of the related security documents governing the Existing Indebtedness.

“FERC” means the Federal Energy Regulatory Commission.

“Financial Statements” has the meaning set forth in Section 3.10(c).

-3-

“Flow of Funds Memorandum” means the flow of funds memorandum dated as of the Closing Date, setting forth the amounts to be contributed to the Company pursuant to Section 2.2, which memorandum shall be reasonably satisfactory to JPM and the Sellers and shall include the exact amounts to be contributed on or prior to the Closing Date, and the Persons (and the account information related thereto) to whom such amounts are to be contributed.

“FPA” means the Federal Power Act, as amended.

“GAAP” means United States generally accepted accounting principles as recognized by the American Institute of Certified Public Accountants, as in effect from time to time, consistently applied and maintained on a consistent basis for a Person throughout the period indicated and consistent with such Person’s prior financial practice.

“Governmental Authority” means any governmental department, commission, board, bureau, agency, court or other instrumentality of any country, state, province, county, parish or municipality, jurisdiction, or other political subdivision thereof.

“Hazardous Substances” means (A) any hazardous materials, hazardous wastes, hazardous substances, toxic wastes, solid wastes, and toxic substances as those or similar terms are defined under any Environmental Laws; (B) any friable asbestos or friable asbestos-containing material; (C) polychlorinated biphenyls (“PCBs”), or PCB-containing materials or fluids; (D) radon; (E) any petroleum, petroleum hydrocarbons, petroleum products, crude oil and any fractions or derivatives thereof; and (F) any other hazardous, radioactive, toxic or noxious substance, material, pollutant, or contaminant that, whether by its nature or its use, is subject to regulation or may give rise to liability under any Environmental Laws.

“Initial Class B Capital Contribution” has the meaning set forth in Section 2.2.

“Insurance Consultant” means Moore & McNeil, or such other consultant agreed by the Parties.

“Interconnection Agreements” means those documents identified as “Interconnection Agreements” in Schedule 3.19.

“Interim Financials” has the meaning set forth in Section 3.10(c).

“Intermediate Company” means OFC 2.

“IRS” means the Internal Revenue Service of the United States of America.

“Knowledge” means the actual knowledge, after due inquiry, of the Persons listed below with respect to the subject matter(s) set forth below and the knowledge each such Person would have as a result of reasonable inquiries of employees of ONI with supervisory or managerial responsibilities related to such matters.

-4-

Name	Sections	Subject Matter
Ohad Zimron, Vice President Operations	Sections 3.1 – 3.31	Representations and Warranties
Barbara Allen, Vice President, Finance & Corporate Services	Sections 3.9, 3.10(a) – (c) (with respect to balance sheets and Financial Statements only)	Tax matters, balance sheets, and Financial Statements
Nir Yahav, Senior Director, Plant Operations Finance	Section 3.10(d)	Operating Statements
Kyle Snyder, Business Development Manager	Section 3.13	Environmental Matters
Ofer Hayat, Risk Manager	Section 3.15	Insurance
Lynn Alster, Vice President and Legal Advisor	Section 3.5	Absence of Litigation

“Leases” means those documents identified as “Real Property Documents” in Schedule 3.19.

“Licenses and Permits” means licenses, permits, certificates, approvals, grants, easements, exemptions, variances and authorizations from, any Governmental Authority.

“Liens” means any liens, pledges, claims, security interests, encumbrances, easements, rights-of-way, mortgages, deeds of trust, covenants, restrictions, rights of first refusal or defects in title.

“Material Adverse Effect” means a material adverse effect on the business, assets, liabilities, financial condition or results of operations of any of (i) the DAC 2 Project Company, (ii) the McGinness Hills 2 Project Company, or (iii) the Company and the Subject Companies, taken as a whole, in each case excluding any effect resulting from (a) any change in political, social, economic, industry, market or financial conditions (including changes in the electric generating, transmission or distribution industry, the wholesale or retail markets for electrical power, the general state of the energy industry, including natural gas and natural gas liquid prices, the transmission system, interest rates, consumer confidence, outbreak of hostilities, terrorist activities or war), whether general or regional in nature or limited to any area in which the Projects are located or any of the Subject Companies operate, (b) any change in Applicable Law or regulatory policy, (c) effects of weather or meteorological events, or (d) the execution or delivery of this Agreement, the consummation of the transactions contemplated hereby or the announcement thereof, other than such changes or events that affect the Company and the Subject Companies materially disproportionally.

“Material Contract” means, (1) a contract for the sale of electric energy or transmission services of a Project; (2) a contract, lease, indenture or security under which the Company or any Subject Company (a) has created, incurred, assumed or guaranteed any indebtedness for borrowed money or obligations under any lease that, in accordance with GAAP, should be capitalized, (b) has created a mortgage, security interest or other consensual encumbrance on any property with a fair market value in excess of five million dollars ($5,000,000), or (c) has a reimbursement obligation in respect of any letter of credit, guaranty, bond, or other credit or collateral support arrangement required to be maintained by any Subject Company under the terms of any contract referred to in clause (1) above; (3) a contract for management, operation or maintenance of a Project; (4) a product warranty or repair contract by or with a manufacturer or vendor of equipment owned or leased by any Subject Company with a fair market value in excess of five million dollars ($5,000,000); (5) the OFC 2 Loan Documents; (6) Real Property Documents; and (7) any other contract that could require payments of more than five million dollars ($5,000,000), in the aggregate for any Subject Company during any fiscal year.

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“McGinness Hills 2 Project” means the approximately 37.5 MW geothermal power project owned by the McGinness Hills 2 Project Company as described in Schedule 1.

“McGinness Hills 2 Project Company” means the Project Company that owns the McGinness Hills 2 Project.

“Membership Interest” has the meaning set forth in the Company LLC Agreement.

“Nonrecourse Liability” has the meaning given to such term in Treasury Regulation Section 1.704-2(b)(3).

“OFC 2” has the meaning set forth in the Recitals.

“OFC 2 Indenture” means that certain Indenture of Trust and Security Agreement, dated as of September 23, 2011, by and among OFC 2 LLC, ORNI 15 LLC, ORNI 39 LLC, ORNI 42 LLC and HSS II, LLC, as Issuers, and Wilmington Trust Company, as Trustee and as Depository.

“OFC 2 Loan Documents” means those documents identified as “OFC 2 Loan Documents” in Schedule 3.19.

“ONI Guaranty” means the Guaranty Agreement made by ONI for the benefit of JPM, attached hereto as Exhibit C, dated the Closing Date.

“Operating Reports” has the meaning set forth in Section 3.10(d).

“Operation and Maintenance Agreements” means those documents identified as “O&M Agreements” in Schedule 3.19.

“Ordinary Course of Business” means the ordinary conduct of business consistent with past custom and practice (including with respect to quantity and frequency).

“Organizational Documents” means articles of incorporation, certificate of incorporation, charter, bylaws, articles of organization, formation or association, regulations, operating agreement, certificate of limited partnership, partnership agreement, and all other similar documents, instruments or certificates executed, adopted, or filed in connection with the creation, formation or organization of a Person, including any amendments thereto.

“Ormat Guarantor” means Ormat Technologies, Inc., a Delaware corporation.

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“ORNI 37 PPA” means the document identified as the “ORNI 37 PPA” on Schedule 3.19.

“ORNI 47” means ORNI 47 LLC, a Delaware limited liability company.

“OTEC Guaranty” means the Guaranty Agreement made by the Ormat Guarantor for the benefit of JPM, attached hereto as Exhibit B, dated the Closing Date.

“Party” and “Parties” has the meaning set forth in the introductory paragraph hereof.

“Permitted Liens” means (a) liens for taxes not yet due or that are being contested in good faith by appropriate proceedings, (b) carriers’, warehousemen’s, mechanics’, materialmen’s, repairmen’s, employees’, contractors’, operators’ or other similar liens or charges securing the payment of expenses not yet due and payable that were incurred in the Ordinary Course of Business of the applicable Project Company, (c) Liens created under the terms of trade or supply contracts incurred in the Ordinary Course of Business of the applicable Project Company that do not have a Material Adverse Effect on either the use of any assets or properties of the applicable Project Company as currently used or the value of such assets or properties, (d) obligations or duties to any Governmental Authority that constitute Liens, arising in the Ordinary Course of Business of the applicable Project Company, under Licenses and Permits and under zoning, building, land use, mineral and resource extraction laws and Environmental Laws applicable to a Project Company or its assets and properties, that do not have a Material Adverse Effect on either the use of any assets or properties of the applicable Project Company as currently used or the value of such assets or properties, (e) obligations or duties constituting Liens under easements, leases or other property rights of record, so long as such obligations or duties do not have a Material Adverse Effect on either the use of any assets or properties of the applicable Project Company as currently used or the value of such assets or properties, (f) Liens created under the Existing Indebtedness Security Documents in relation to the Existing Indebtedness and (g) other encumbrances and exceptions that are incurred in the Ordinary Course of Business of the applicable Project Company, are not incurred for borrowed money and do not have a Material Adverse Effect on either the use of any assets or properties of the applicable Project Company as currently used or the value of such assets or properties or other liens otherwise addressed in clause (b) of this definition listed in the Title Policy for each Project.

“Person” means an individual, corporation, partnership, limited liability company, association, trust, unincorporated organization, or other entity.

“Placed in Service” means, with respect to each Project, that (a) the Project has obtained the necessary permits and licenses for operation; (b) critical preoperational testing has been completed for the generation of electric energy for sale to customers; (c) the respective Project Company has custody and control of the Project; (d) the Project is synchronized into a transmission power grid; and (e) the Project routinely supplies power to the transmission power grid for sale to customers.

“PPAs” means those documents identified as “Power Purchase Agreements” in Schedule 3.19.

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“Pre-Closing Tax Period” has the meaning set forth in Section 5.2.

“Project Companies” means, each of the limited liability companies listed on Schedule 1.

“Projects” means the geothermal power projects described on Schedule 1.

“Property Tax” means any tax resulting from and relating to the assessment of real or personal property by a Governmental Authority.

“PTCs” means the tax credits pursuant to Section 45 of the Code (or any successor to such section of the Code) for the sale of electricity produced from certain renewable resources.

“PTC Eligible Projects” means the equipment necessary for electricity generation from geothermal resources with respect to the portions of the McGinness Hills 2 Project and the DAC 2 Project that are projected in the Base Case Model to produce PTCs. For the avoidance of doubt, this definition does not include the geothermal reservoir, monitoring equipment, or transmission equipment.

“PUHCA” has the meaning set forth in Section 3.25.

“PURPA” has the meaning set forth in Section 3.23.

“QF” has the meaning set forth in Section 3.23.

“Real Property Documents” means the material deeds, leases, easements, licenses, special use permits, setback waiver agreements or other material contracts to which any Subject Company (or any of its Affiliates) is a party or by which it or its assets are bound and that grant, convey, assign or otherwise affect real property interests relating to the Projects or the business or assets of such Subject Company in any material respect.

“Release” or “Released” means any release, spill, leak, emission, deposit, pumping, pouring, emptying, discharging, injecting, escaping, leaching, disposing, dumping, or dispersion of Hazardous Substances into, under, above, onto or from air (including ambient, workplace or indoor air), soil, sediments, land surface (whether above or below water), subsurface strata, or water (including, without limitation, territorial, coastal and inland surface waters, groundwater and streams).

“Reports” means the reports prepared by the Consultants and identified in Schedule 2.5(l).

“Sanctioned Country” means, at any time, a country or territory which is itself the subject or target of any Sanctions.

“Sanctioned Person” means, at any time, (a) any Person listed in any Sanctions-related list of designated Persons maintained by the Office of Foreign Assets Control of the U.S. Department of the Treasury, the U.S. Department of State, or the United Nations Security Council, the European Union or any European Union member state, (b) any Person operating, organized or resident in a Sanctioned Country or (c) any Person owned or controlled by any such Person or Persons.

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“Sanctions” has the meaning set forth in Section 3.12(b)(iii).

“Schedules” means the Schedules attached to this Agreement.

“SCPPA” means Southern California Public Power Authority.

“Senior Notes” has the meaning set forth in the Company LLC Agreement.

“Steam Resource” has the meaning set forth in Section 3.9(g).

“Straddle Period” means any taxable period that includes, but does not end on, the Effective Date.

“Subject Companies” means, collectively, the Project Companies and the Intermediate Company (and each Project Company and the Intermediate Company, individually, a “Subject Company”).

“Surveyor” has the meaning set forth in Section 2.5(x).

“Tax” or “Taxes” means any taxes, assessments, fees and other governmental charges imposed by any Governmental Authority, including income, profits, gross receipts, net proceeds, alternative or add-on minimum, ad valorem, value added, turnover, sales, use, property, personal property (tangible and intangible), environmental, stamp, leasing, lease, user, excise, duty, franchise, capital stock, transfer, registration, license, withholding, social security (or similar), unemployment, disability, payroll, employment, fuel, excess profits, occupational, premium, windfall profit, severance, estimated, or other tax of any kind whatsoever, including any interest, penalty, or addition thereto, whether disputed or not.

“Tax Returns” means any return, report, statement, information return or other document (including any amendments thereto and any related or supporting information) filed or required to be filed with any Governmental Authority in connection with the determination, assessment, collection or administration of any Taxes or the administration of any laws, regulations or administrative requirements relating to any Taxes.

“Title Company” means any of Chicago Title Insurance Company, Fidelity National Title Insurance Company, or First American Title Insurance Company.

“Title Policy” means an owner’s policy of title insurance meeting the requirements of Schedule 2.5(v) to be dated as of the Closing Date.

“Transaction Documents” means this Agreement, the Company LLC Agreement, the Operation and Maintenance Agreements, the OTEC Guaranty, the ONI Guaranty, and each of the other documents required to be delivered under this Agreement on the Closing Date.

“Transaction Expenses” has the meaning set forth in Section 8.6.

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“Transfer Taxes” has the meaning set forth in Section 5.1.

“Treasury Regulations” means the regulations promulgated under the Code, by the Treasury, as such regulations may be amended from time to time. All references herein to specific sections of the regulations shall be deemed also to refer to any corresponding provisions of succeeding regulations, and any reference to temporary regulations shall be deemed also to refer to any corresponding provisions of final regulations.

“Unrelated Person” means a Person that is not “related”, within the meaning of Section 45(e)(4) of Code, to any Person to whom any of the Project Companies sells electricity during the period the Company is entitled to PTCs on such electricity.

“Year End Financials” has the meaning set forth in Section 3.10(c).

Section 1.2     Other Definitional Provisions.

(a)     All terms in this Agreement shall have the defined meanings when used in any certificate or other document made or delivered pursuant hereto unless otherwise defined therein.

(b)     As used in this Agreement and in any certificate or other documents made or delivered pursuant hereto or thereto, accounting terms not defined in this Agreement or in any such certificate or other document, and accounting terms partly defined in this Agreement or in any such certificate or other document to the extent not defined, shall have the respective meanings given to them under GAAP. To the extent that the definitions of accounting terms in this Agreement or in any such certificate or other document are inconsistent with the meanings of such terms under GAAP, the definitions contained in this Agreement or in any such certificate or other document shall control.

(c)     The words “hereof,” “herein,” “hereunder,” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement. Section references contained in this Agreement are references to Sections in this Agreement unless otherwise specified. The term “including” shall mean “including without limitation.”

(d)     The definitions contained in this Agreement are applicable to the singular as well as the plural forms of such terms and to the masculine as well as to the feminine and neuter genders of such terms.

(e)     Any agreement, instrument or statute defined or referred to herein or in any instrument or certificate delivered in connection herewith means such agreement, instrument or statute as from time to time amended, modified or supplemented and includes (in the case of agreements or instruments) references to all attachments thereto and instruments incorporated therein.

(f)     Any references to a Person are also to its successors and permitted assigns.

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(g)     All Article and Section titles or captions contained in this Agreement or in any Exhibit or Schedule referred to herein and the table of contents of this Agreement are for convenience only and shall not be deemed a part of this Agreement or affect the meaning or interpretation of this Agreement. Unless otherwise specified, all references herein to numbered Articles and Sections are to Articles and Sections of this Agreement, as applicable, and all references herein to Schedules or Exhibits are to Schedules and Exhibits to this Agreement.

(h)     Unless otherwise specified, all references contained in this Agreement, in any Exhibit or Schedule referred to herein or in any instrument or document delivered pursuant hereto to dollars or “$” shall mean United States dollars.

(i)     The Parties have participated jointly in the negotiation and drafting of this Agreement. In the event an ambiguity or question of intent or interpretation arises, this Agreement shall be construed as if drafted jointly by the Parties and no presumption or burden of proof shall arise favoring or disfavoring any Party by virtue of the authorship of any of the provisions of this Agreement.

Article II
CAPITAL CONTRIBUTIONS; MEMBERSHIP INTERESTS

Section 2.1     Issuance of Class B Membership Interests. Upon the terms and subject to the conditions set forth in this Agreement, on the Closing Date, JPM shall make a capital contribution to the Company and OrLeaf will cause the Company to issue to JPM the Class B Membership Interests in the Company in accordance with the terms of the Company LLC Agreement.

Section 2.2     Use of Proceeds. The aggregate capital contribution by JPM in exchange for the Class B Membership Interests will be a payment to the Company on the Closing Date of sixty-two million one hundred forty-nine thousand dollars ($62,149,000) (the “Initial Class B Capital Contribution”), made by wire transfer of immediately available United States dollars to such account or accounts of the Company as OrLeaf may designate in a written notice given to JPM not later than two Business Days before the Closing Date, which shall be applied by the Company on the Closing Date as follows:

(a)     First, to immediately pay all Transaction Expenses payable in accordance with Section 8.6 and owed as of the Closing Date;

(b)     Second, the funds remaining after payment of all amounts described in clause (a) above, shall be distributed by the Company to OrLeaf and deposited into an account specified by OrLeaf.

Section 2.3     Tax Treatment. For federal income tax purposes, each of the Parties intends the transactions contemplated in Section 2.1 to be treated as follows (it being understood that no representation or warranty is being made by any Party with respect to such treatment hereunder):

(a)     Prior to Closing, the Company is treated as an entity disregarded as separate from OrLeaf (for federal income tax purposes);

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(b)     On the Closing Date, the Company will be converted into a partnership for federal income tax purposes with JPM and OrLeaf as partners.  OrLeaf will be treated as contributing all of the assets of the Company to the newly formed partnership in exchange for the Class A Membership Interests, and JPM will be treated as contributing the Initial Class B Capital Contribution in exchange for the Class B Membership Interests.  The Parties agree to report the Company’s distribution of cash to OrLeaf described in Section 2.3 as a reimbursement of preformation expenditures within the meaning of Treasury Regulations section 1.707-4(d), and not as a sale of the assets; and

(c)     The Existing Indebtedness will be treated as Nonrecourse Liabilities of the Company. To the extent the Existing Indebtedness constitutes “excess Nonrecourse Liabilities” described in Treasury Regulation Section 1.752-3(a)(3), such excess Nonrecourse Liabilities will be allocated to JPM and OrLeaf in the same ratio in which they share excess Nonrecourse Liabilities under Section 5.4(b) of the Company LLC Agreement. Accordingly, the Parties agree to treat the starting tax basis for tax reporting purposes of the Class B Membership Interests as the Initial Class B Capital Contribution plus five percent (5%) of the Existing Indebtedness that represents excess Nonrecourse Liabilities and of the Class A Membership Interests as the carryover basis in the assets that Newco was deemed to contribute to the Company on the Closing Date plus ninety-five percent (95%) of the Existing Indebtedness that represents excess Nonrecourse Liabilities plus one hundred percent (100%) of the amount, if any, of Code Section 704(c) “minimum gain” Nonrecourse Liabilities.

Section 2.4     Closing. The consummation of the transactions contemplated in Section 2.1 (the “Closing”) will take place (i) at the offices of Chadbourne & Parke LLP in New York, New York at 10:00 a.m. (Eastern time) (the “Effective Time”) on the date (the “Closing Date”) upon which all of the conditions in Section 2.5 and Section 2.6 have either been satisfied or, in the case of conditions not satisfied, waived in writing by the Party entitled to the benefit of such conditions or (ii) at such other place and time as JPM and the Sellers may agree in writing. The rights and obligations of the Parties hereunder and under the documents delivered pursuant to Section 2.5 and Section 2.6 shall not take effect until the Effective Time and such documents shall be of no force and effect until the Closing is consummated.

Section 2.5     Conditions Precedent to the Obligations of JPM in Connection with the Closing. The obligations of JPM to consummate the Closing will be subject to the satisfaction or waiver by JPM of each of the conditions set forth below; provided, however, that such consummation of the Closing by JPM shall not act as a waiver of, or otherwise affect any rights and remedies arising from, the representations and warranties set forth herein and in any certificates delivered or to be delivered pursuant to this Agreement:

(a)     Each of the representations and warranties by or on behalf of the Sellers in Article III of this Agreement, of the Ormat Guarantor in the OTEC Guaranty, and of ONI in the ONI Guaranty shall be true and correct in all material respects as of the Closing Date (other than those qualified by a reference to materiality or Material Adverse Effect, which representations and warranties shall be true and correct in all respects, or those that relate to an earlier date, which shall be true and correct in all material respects as of such earlier date).

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(b)     OrLeaf shall have delivered or cause to be delivered to JPM true, correct and complete copies of each of the Licenses and Permits set forth on Schedule 3.14.

(c)     There shall not be any injunction, judgment, order, decree or ruling in effect or pending that would prevent or inhibit consummation of the transactions contemplated by the Transaction Documents that are being executed at Closing, and no action, complaint, investigation, suit or other proceeding shall be threatened in writing or instituted by any private party or Governmental Authority, and remain pending on the Closing Date, which (i) restrains or prohibits or otherwise challenges the performance of the obligations of the Parties, or (ii) seeks material damages or penalties in relation to such obligations.

(d)     JPM shall have received true, correct and complete, fully executed copies of all Material Contracts, each in form and substance reasonably satisfactory to JPM and each of which shall be in full force and effect and no event shall have occurred and be continuing that either (i) constitutes a default thereunder by Ormat Guarantor, ONI, OrLeaf, the Company or any Subject Company or any other party thereto or (ii) with notice or lapse of time, or both, could reasonably be expected to result in a default thereunder.

(e)     JPM shall have received fully executed counterparts of this Agreement (including the Schedules and Exhibits hereto), the Company LLC Agreement, the OTEC Guaranty and the ONI Guaranty, in each case in form and substance reasonably satisfactory to JPM.

(f)     OrLeaf shall have delivered or cause to be delivered to JPM an officer’s certificate of an authorized officer of each of ONI and OrLeaf (i) certifying that each of the conditions set forth in Section 2.6 have been fulfilled to the satisfaction of each of ONI and OrLeaf or have been waived by each of ONI and OrLeaf; (ii) certifying that each of the representations and warranties set forth in Article III are true and correct in all material respects as of the Closing Date (other than those qualified by a reference to materiality or Material Adverse Effect, which representations and warranties shall be true and correct in all respects, or those that relate to an earlier date, which shall be true and correct in all material respects as of such earlier date); (iii) attaching true, accurate and complete copies of the Organizational Documents of each of ONI, OrLeaf, the Company and the Subject Companies and resolutions of each of ONI, OrLeaf, and the Company authorizing the execution of the Transaction Documents that are being executed in connection with the Closing and to which it is a party.

(g)     JPM shall have received written confirmations issued by a Governmental Authority of each Subject Company’s federal tax identification number (or similar documentation reasonably acceptable to JPM).

(h)     Each of ONI and OrLeaf shall have delivered to JPM a certificate of incumbency from the secretary or assistant secretary of each of ONI and OrLeaf as to the officers of ONI and OrLeaf who sign the Transaction Documents that are being executed in connection with the Closing on behalf of ONI and OrLeaf, respectively.

(i)     OrLeaf shall have delivered to JPM an affidavit of non-foreign status that complies with Section 1445 of the Code, duly executed by OrLeaf.

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(j)     OrLeaf shall have delivered or cause to be delivered to JPM good standing certificates and certificates of good standing as to foreign corporations/limited liability companies for each of Ormat Guarantor, ONI, OrLeaf, the Company and the Subject Companies.

(k)     OrLeaf shall have (i) caused the Company to issue the Class B Membership Interests to JPM and the Class A Membership Interests to OrLeaf in accordance with the terms of the Company LLC Agreement, and (ii) delivered to JPM the certificate of Class B Membership Interests.

(l)     JPM shall have received copies of each Report, each in form and substance reasonably satisfactory to JPM and either (i) addressed to JPM or (ii) accompanied by a letter executed by the applicable Consultant permitting JPM to rely on such Report, in form and substance reasonably satisfactory to JPM.

(m)     JPM shall have received (i)  a legal opinion of Chadbourne and Parke LLP, counsel to the Ormat Guarantor, ONI, OrLeaf, the Company and each Subject Company, (ii) a legal opinion of Morris James LLP, Delaware counsel, as to the enforceability of the Company LLC Agreement against each of the Members (as defined in the Company LLC Agreement) thereto, and (iii) a tax opinion of Hunton & Williams LLP, in each case in form and substance reasonably satisfactory to JPM.

(n)     JPM shall have received a written notice of the Closing not less than two (2) Business Days prior to the Closing Date.

(o)     JPM shall have received the Base Case Model, reasonably satisfactory in form and substance to JPM.

(p)     OrLeaf shall have delivered or cause to be delivered to JPM the Operating Reports.

(q)     No condemnation is pending or threatened in writing, that is material to the ownership or operation of the Projects.

(r)     No unrepaired casualty exists with respect to any Project or any portion thereof, in each case that is material to the ownership or operation of the Project.

(s)     Except as listed on Schedule 3.18, all assets owned by the Company and by each of the Subject Companies are free and clear of all Liens, other than Permitted Liens.

(t)     JPM shall have received all consents, approvals and filings required to be obtained or made by JPM to execute, deliver and perform the Transaction Documents to which JPM is a party (including the approval of JPM’s investment committee and Board of Directors) that are required to be executed and delivered on the Closing Date (but excluding any consents, approvals, and filings to be obtained or made after the Closing Date as set forth on Schedule 2.5(t)) and such consents, approvals and filings shall be in full force and effect as of the Effective Time.

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(u)     JPM shall have received true, correct and complete copies of insurance certificates from insurance brokers or carriers or other evidence reasonably satisfactory to JPM, in consultation with the Insurance Consultant, evidencing that the insurance policies and coverage described in Schedule 3.15 are in place and in full force and effect as of the Effective Time and include the terms and conditions set forth in Schedule 3.15.

(v)     JPM shall have received copies of a Title Policy for each Project issued by the Title Company, in each case conforming to the requirements set forth in Schedule 2.5(v).

(w)     An updated ALTA/ACSM land title survey for each Project depicting the real property and its boundaries, prepared by a professional land surveyor (“Surveyor”), in each case conforming to the requirements set forth in Schedule 2.5(v) and otherwise subject to the reasonable satisfaction of the Title Company so as to enable the issuance of the Title Policy for each Project.

(x)     No material adverse change in law or Tax law affecting any Project has occurred that would have a material adverse impact on the PTCs expected to be available to JPM as set forth in the Base Case Model.

(y)     No material adverse change in the financial condition or ability of the Ormat Guarantor, ONI, OrLeaf, the Company or any Subject Company to perform their respective obligations under the Material Contracts has occurred.

(z)     JPM has received documentation reasonably satisfactory to it that supports the fact that each PTC Eligible Project, or portion thereof, was Placed in Service on the date set forth on Schedule 3.9(f).

(aa)     JPM shall have received the Flow of Funds Memorandum in form and substance reasonably satisfactory to it.

(bb)     The 60 day notice period under Section 12.5 of the ORNI 37 PPA shall have expired or SCPPA shall have waived such notice requirement in a manner reasonably acceptable in form and substance to JPM (such acceptance not to be unreasonably withheld, delayed, or conditioned).

(cc)     JPM shall have received evidence reasonably satisfactory to it that all third party consents and approvals required under the OFC 2 Loan Documents have been obtained.

Section 2.6     Conditions Precedent to the Obligations of the Sellers in Connection with the Closing. The obligations of the Sellers to consummate the Closing will be subject to the satisfaction or waiver by the Sellers of each of the conditions set forth below; provided, however, that such consummation of the Closing by the Sellers shall not act as a waiver of, or otherwise affect any rights and remedies arising from, the representations and warranties set forth herein and in any certificates delivered or to be delivered pursuant to this Agreement:

(a)     Each of the representations and warranties of JPM in Article IV of this Agreement shall be true and correct in all material respects as of the Closing Date (other than those qualified by a reference to materiality or Material Adverse Effect, which representations and warranties shall be true and correct in all respects, or those that relate to an earlier date, which shall be true and correct in all material respects as of such earlier date).

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(b)     JPM shall have made the Initial Class B Capital Contribution in the manner set forth in Section 2.2.

(c)     JPM shall have delivered to the Sellers (i) an officer’s certificate of an authorized officer of JPM certifying that each of the representations and warranties set forth in Article IV are true and correct in all material respects as of the Closing Date (other than those qualified by a reference to materiality or Material Adverse Effect, which representations and warranties shall be true and correct in all respects, or those that relate to an earlier date, which shall be true and correct in all material respects as of such earlier date) and (ii) a certificate regarding corporate matters from an authorized officer of JPM, in JPM’s customary form.

(d)     JPM shall have delivered to the Sellers certificates of incumbency from the secretary or assistant secretary of JPM as to the officers of JPM who sign the Transaction Documents that are being executed in connection with the Closing on behalf of JPM.

(e)     The Company LLC Agreement shall have been duly executed by JPM and delivered to OrLeaf.

(f)     JPM shall have delivered to the Sellers a good standing certificate.

Article III
REPRESENTATIONS AND WARRANTIES OF the Sellers

Each of ONI and OrLeaf hereby represents and warrants to JPM as to ONI, OrLeaf, the Company, and the Subject Companies, on and as of the Closing Date, as follows:

Section 3.1     Organization, Good Standing, Etc. of ONI and OrLeaf.

(a)     ONI is a corporation, duly organized, validly existing and in good standing under the laws of the State of Delaware. ONI has the corporate power and authority to own, lease and operate its properties and to carry on its business as being conducted on the date hereof. ONI is duly qualified to do business as a foreign corporation and is in good standing under the laws of each state in which either the ownership or use of the properties owned or used by it, or the nature of the activities conducted by it, requires such qualification, except where the absence of qualification could not reasonably be expected to have a Material Adverse Effect.

(b)     OrLeaf is a limited liability company, duly organized, validly existing and in good standing under the laws of the State of Delaware. OrLeaf has the requisite power and authority to own, lease and operate its properties and to carry on its business as being conducted on the date hereof. OrLeaf is duly qualified to do business as a foreign limited liability company and is in good standing under the laws of each state in which either the ownership or use of the properties owned or used by it, or the nature of the activities conducted by it, requires such qualification, except where the absence of qualification could not reasonably be expected to have a Material Adverse Effect.

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Section 3.2     Organization, Good Standing, Etc. of the Company and Subject Companies. The Company is a limited liability company duly organized, validly existing and in good standing under the laws of the State of Delaware, and each of the Subject Companies is a limited liability company or partnership duly organized, validly existing and in good standing under the laws of the State of Delaware, as more specifically described on Schedule 1. Each of the Company and the Subject Companies has the requisite power and authority to own, lease and operate its properties and to carry on its business as now being conducted. Each of the Company and the Subject Companies is duly qualified to do business as a foreign limited liability company and is in good standing under the laws of each state in which either the ownership or use of the properties owned or used by it, or the nature of the activities conducted by it, requires such qualification. Each of the Organizational Documents described on Schedule 3.2 has not been further amended and is currently in full force and effect.

Section 3.3     Authority. Each of ONI, OrLeaf, the Company, and the Subject Companies has the necessary power and authority to enter into the Transaction Documents that are being executed in connection with the Closing and to which it is party, to perform its obligations thereunder and to consummate the transactions contemplated therein. All corporate or limited liability company actions or proceedings to be taken by or on the part of ONI, OrLeaf, the Company, and the Subject Companies to authorize and permit the due execution and valid delivery by ONI, OrLeaf, the Company, and the Subject Companies of the Transaction Documents that are being executed in connection with the Closing and to which it is a party and required to be duly executed and validly delivered by it pursuant thereto, the performance by ONI, OrLeaf, the Company, and the Subject Companies of its obligations thereunder, and the consummation by ONI, OrLeaf, the Company, and the Subject Companies of the transactions contemplated therein, have been duly and properly taken. The Transaction Documents have been duly executed and delivered by ONI, OrLeaf, the Company, and the Subject Companies, as applicable, and constitute the legal, valid, and binding obligation of ONI, OrLeaf, the Company, and the Subject Companies, as applicable, enforceable in accordance with their terms, except as such enforceability (i) may be limited by applicable bankruptcy, insolvency, reorganization, fraudulent conveyance, moratorium or other similar laws affecting the enforcement of creditors’ rights and remedies generally and (ii) is subject to general principles of equity (regardless of whether enforceability is considered in a proceeding in equity or at law).

Section 3.4     No Conflicts. The execution and delivery of the Transaction Documents that are being executed in connection with the Closing and to which each of ONI, OrLeaf, the Company or any Subject Company is a party and the performance by each of ONI, OrLeaf, the Company and any Subject Company of its respective obligations under such Transaction Documents will not, (i) violate any Applicable Law to which ONI, OrLeaf, the Company or any of the Subject Companies or any of their respective properties are subject, (ii) conflict with or cause a breach of any provision in the Organizational Documents of ONI, OrLeaf, the Company or any Subject Company, (iii) cause a breach of, constitute a default under, cause the acceleration of, create in any party the right to accelerate, terminate, modify or cancel, or require any authorization, consent, waiver or approval under any contract, license, instrument, decree, judgment or other arrangement to which ONI, OrLeaf, the Company or any Subject Company is a party or under which any of them is bound or to which any of their assets are subject (or result in the imposition of a Lien upon any such assets), except (in the case of this clause (iii) only) for any that would not reasonably be expected to have a Material Adverse Effect or (iv) except as otherwise described in Schedule 3.4, require any notice to, filing with, or authorization, consent or approval of, any Governmental Authority, other than any such filing, authorization, consent or approval that is ministerial in nature and can be reasonably expected to be made and obtained in due course on commercially reasonable terms and conditions when needed.

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Section 3.5     Absence of Litigation. Except as set forth on Schedule 3.5, no action, suit, claim, demand, investigation or other proceeding is pending against any of ONI, OrLeaf, the Company or any Subject Company and, to the Knowledge of the Sellers, none of ONI, OrLeaf, the Company or any Subject Company is threatened with being made a party to any action, suit, proceeding, hearing or investigation of, in, or before any Governmental Authority or before any arbitrator, other than any such instance with respect to ONI that would not reasonably be expected to have a Material Adverse Effect.

Section 3.6     Ownership.

(a)     Immediately prior to the Closing, OrLeaf owns of record and beneficially 100% of the Membership Interests, subject to no Liens. The Company owns of record and beneficially 100% of the membership interests in the Intermediate Company and 100% of the membership interests in the DAC 2 Project Company, subject to no Liens other than Permitted Liens of the type described in clauses (d) and (f) of the definition thereof. The Intermediate Company holds 100% of the membership interests in each of the Project Companies (other than the DAC 2 Project Company) subject to no Liens other than Permitted Liens of the type described in clauses (d) and (f) of the definition thereof.

(b)     Other than as set forth on Schedule 3.6, OrLeaf has no, and has never had any, subsidiaries. Other than as set forth on Schedule 3.6, the Company has no, and has never had any, subsidiaries. Other than as set forth on Schedule 3.6, the Intermediate Company has no, and has never had any, subsidiaries. Each of the Project Companies has no, and has never had any, subsidiaries.

(c)     There are no outstanding options, warrants, calls, puts, rights of first refusal, convertible securities or other contracts of any nature (i) obligating OrLeaf to issue, deliver or sell membership interests, or other securities in the Company, except as provided herein, (ii) obligating the Company to issue, deliver or sell membership interests, or other securities in the Intermediate Company, or (iii) obligating the Intermediate Company to issue, deliver or sell membership interests, or other securities in any of the Project Companies. None of the Subject Companies has engaged in any business other than the ownership, development, construction, financing or operation of the respective Projects.

Section 3.7     Sufficiency of Assets. Except as set forth on Schedule 3.7, as of Closing, the assets of the Company, whether real, personal, tangible or intangible and whether leased, owned or licensed, comprising the Projects constitute all of the assets required for or used in the operation of the Projects as presently operated or proposed to be operated and no other assets are required or necessary in the operation of the Projects in the Ordinary Course of Business; provided, however, that nothing contained herein shall constitute any representation or warranty regarding the sufficiency or adequacy of the geothermal resources available to the Projects.

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Section 3.8     Valid Interests. The Class B Membership Interests will constitute valid membership interests in the Company, and are being issued free and clear of any Liens except for obligations that will apply to JPM upon its admission as a member of the Company under the Company LLC Agreement.

Section 3.9     Tax Matters.

(a)     Each Project is located in its entirety in the United States.

(b)     No portion of any PTC Eligible Project (i) consists of property, materials or parts used by any person other than the relevant Project Company, excluding property, materials or parts comprising a portion of the DAC 2 Project that are used by both the DAC 2 Project Company and ORNI 47 as set forth in the applicable Material Contracts, and (ii) was used by the relevant Project Company prior to the applicable Placed in Service date for such PTC Eligible Project as set forth on Schedule 3.9(f) other than in connection with the construction, start-up, testing and commissioning of such PTC Eligible Project.

(c)     No person has an ownership interest, or a right to acquire an ownership interest, in the Project Companies or the Projects, other than as set forth on Schedules 3.6 and 3.9(c).

(d)     No PTC Eligible Project has received or benefited from, for purposes of Section 45(b)(3) of the Code, (i) any grant provided by the United States, any state or any political subdivision of a state for use in connection with the PTC Eligible Project, (ii) any issue of state or local government obligations used to provide financing for the PTC Eligible Project the interest on which is exempt from federal income tax under Section 103 of the Code, (iii) any subsidized energy financing provided (directly or indirectly) under a federal, state, or local program provided in connection with the PTC Eligible Project or (iv) any other credit allowable with respect to any property that is part of the PTC Eligible Project.

(e)     OrLeaf is an Unrelated Person.

(f)     Each PTC Eligible Project was Placed in Service on the date set forth on Schedule 3.9(f) with respect to such PTC Eligible Project and first claimed PTCs on such date. The Company or applicable Subject Company has treated such date as the date the PTC Eligible Project was Placed in Service and has not received any notification from the IRS to the contrary.

(g)     Each PTC Eligible Project has, at all times following the date set forth on Schedule 3.9(f) with respect to such PTC Eligible Project, been (i) located in its entirety in the United States, (ii) continuously generating electricity from a geothermal reservoir consisting of natural heat which is stored in rocks or in an aqueous liquid or vapor (whether or not under pressure) (other than for maintenance and curtailment events) (such reservoirs for all Projects, collectively, the “Steam Resource”) and (iii) making all sales of generated electricity to an Unrelated Person.

(h)     OrLeaf is a “United States person” not subject to withholding under Section 1445 of the Code.

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(i)     No action has been taken that would cause any of the assets of the Company or any Subject Company to constitute “tax–exempt” use property within the meaning of Section 168(h) of the Code. No tangible property of any Subject Company is imported property of the kind described under Section 168(g)(6) of the Code.

(j)     On the date set forth on Schedule 3.9(f) with respect to each PTC Eligible Project, as applicable, the value of equipment used prior to being included in the PTC Eligible Project did not exceed twenty percent (20%) of the sum of (A) the value of such used equipment and (B) the cost of new equipment Placed in Service on the relevant date listed on Schedule 3.9(f). From the date set forth on Schedule 3.9(f) with respect to each PTC Eligible Project, as applicable, until the Effective Time, the cost of capital improvements to the PTC Eligible Project did not exceed four times the value of the equipment that was part of the PTC Eligible Project on the relevant date set forth on Schedule 3.9(f).

(k)     Neither the Sellers nor any Subject Company has received any notification from the IRS that the PTCs are not available or may not be available for any PTC Eligible Project.

(l)     No private letter ruling has been requested from the IRS in connection with the transactions contemplated under the Transaction Documents that are being executed at Closing.

(m)     Except as set forth on Schedule 3.9(m), none of ONI, OrLeaf, the Company or any Subject Company has applied for a grant with respect to the Projects from the U.S. Treasury Department under Section 1603 of the American Recovery and Reinvestment Tax Act of 2009. No investment tax credit pursuant to Section 48 of the Code has been claimed with respect to the PTC Eligible Projects or any portion thereof.

(n)     Neither the Company nor any Subject Company has elected to be characterized as an association taxed as a corporation for United States federal income tax purposes. Neither the Company nor any Subject Company has (i) except for returns required to be filed by entities subject to tax as partnerships for federal income tax purposes, filed any federal income Tax Returns or (ii) taken any action (or failed to take any action) that would cause (A) the Company to be treated as an entity other than a partnership for federal income tax purposes or (B) any Subject Company to be treated for federal income tax purposes other than as a partnership or “disregarded entity” for federal income tax purposes.

(o)     Each Subject Company has respectively treated the Existing Indebtedness as debt for United States federal income tax purposes and shall not have taken an inconsistent position in any filing with the IRS.

(p)     (i) Each of the Company and each Subject Company has timely filed, or has caused to be filed on its behalf, all federal Tax Returns and all other material Tax Returns required to be filed (after giving effect to any extensions that have been requested by, and granted to such party by the applicable Governmental Authority) and has paid, or has caused to be paid or withheld on its behalf, all Taxes shown as due on such returns, (ii) to the Sellers' Knowledge, all such Tax Returns are complete and accurate in all material respects, and (iii) each of the Company and each Subject Company has complied with all Applicable Laws relating to the payment, collection, or withholding of any Tax and the reporting and remittance thereof to the applicable Governmental Authorities in all material respects; provided, however, other than as expressly stated in Sections 3.9(a)–(m), (o), (r)–(v), no representation is being made about the income tax characteristics of the Projects (including the depreciation or depletion allowances for the Projects and whether the output therefrom qualifies for PTCs).

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(q)     There are no claims pending for any additional Tax assessed by any Governmental Authority against the Company or the Subject Companies and no deficiency for any Taxes of the Company or any Subject Company has been assessed and remains outstanding nor, to the Knowledge of OrLeaf, are threatened or proposed. There are no Tax Returns filed by or with respect to the Company or any Subject Company that are currently being audited by any Governmental Authority or have been so audited, nor, to the Knowledge of the Sellers, are any audits, claims, assessments, levies, administrative proceedings, or lawsuits pending or threatened (formally or informally, orally or in writing) against the Company or any Subject Company or as to the respective assets of the Company or any such Subject Company to which the Company or any such Subject Company could be made subject. Neither the Company nor any Subject Company has waived any statute of limitations or agreed to any extension of time with respect to (i) the filing of any Tax Return or (ii) any Tax assessment or deficiency, in each case, which has not been resolved. There are no proceedings now pending or to the Knowledge of the Sellers threatened against the Company or any Subject Company with respect to any Tax or any matters under discussion with any Governmental Authority relating to any Tax. No claim has been made or threatened by a Governmental Authority in a jurisdiction where the Company or any Subject Company does not file Tax Returns that the Company or any Subject Company is subject to taxation by that jurisdiction. Other than as set forth on Schedule 3.9(q), no power of attorney currently in force has been granted by ONI, OrLeaf, the Company or any Subject Company with respect to the Taxes of the Company or any Subject Company. Neither the Sellers, with respect to the Company or any Subject Company, or the Company or any Subject Company has received any material written ruling of a taxing authority relating to Taxes. Neither the Company nor any Subject Company has (i) entered into any material agreement as to the indemnification for, contribution to or payment of Taxes of any other Person or (ii) liability for Taxes of any Person as a transferee or successor, by contract or otherwise, other than customary tax indemnity provisions in any Transaction Document or Material Contract and other than any agreement entered into in the ordinary course of business. State and local (including property) Taxes are accurately reflected in the Base Case Model, subject to any change in assessment or change in law after the Effective Date.

(r)     All electricity generated by any PTC Eligible Project that is capable of being sold is being sold to an Unrelated Person and no more of such electricity than is necessary is being used to satisfy the load requirements of any Project.

(s)     The Sellers (as applicable) or the applicable Subject Company, as the case may be, has been claiming cost recovery deductions in accordance with Section 611 of the Code and the applicable Treasury Regulations for depletion of the Steam Resource since the respective Seller or the applicable Subject Company, as the case may be, acquired an economic interest in such Steam Resource.

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(t)     Neither the Sellers nor any Subject Company has received any notification from the IRS that cost recovery deductions pursuant to Section 611 of the Code for depletion of the Steam Resource are not available or may not be available.

(u)     No portion of the tax basis of any assets owned by the Company or any Subject Company is attributable to intangible drilling and development costs capitalized pursuant to Section 59(e) of the Code.

(v)     Schedule 3.9(v) sets forth the tax basis, asset cost segregation and depreciation conventions, methods and periods reported on the federal tax returns filed by the taxpayer treated as the owner of each Subject Company’s assets, prior to the Closing Date, as well as a good faith current estimate of the DAC 2 Project tax basis step-up resulting from the acquisition by Northleaf Geothermal LLC of 36.75% of the DAC 2 Project prior to its contribution to the Company, for which no assurance can be given that the estimate will not change.

Section 3.10     Balance Sheets, Financial Statements and Operating Reports. OrLeaf has previously delivered or cause to be delivered to JPM true, correct and complete copies of:

(a)     the most recently available unaudited, consolidated balance sheet of the Intermediate Company which includes each Project Company (other than the DAC 2 Project Company) (the “Current Balance Sheet”). The Current Balance Sheet presents fairly in all material respects the financial conditions and results of operations of the Company and the Subject Companies (other than the DAC 2 Project Company) for the periods presented in accordance with GAAP consistently applied, subject to normal year-end audit adjustments and the absence of footnotes.

(b)     the most recently available unaudited balance sheet and statements of income, changes in members' equity, and cash flow of the DAC 2 Project Company (the “DAC 2 Balance Sheet”). The DAC 2 Balance Sheet presents fairly in all material respects the financial conditions and results of operations of the DAC 2 Project Company for the periods presented in accordance with GAAP consistently applied, subject to normal year-end audit adjustments and the absence of footnotes.

(c)     (i) the consolidated audited financial statements of the Intermediate Company which includes each Project Company (other than the DAC 2 Project Company) for the year ended December 31, 2013, December 31, 2014 and December 31, 2015 (the “Year End Financials”), and (ii) the consolidated unaudited financial statements of the Intermediate Company which includes each Project Company (other than the DAC 2 Project Company) as of September 30, 2016 (the “Interim Financials” and together with the Year End Financials, the “Financial Statements”). The Financial Statements present fairly in all material respects the financial conditions and results of operations of the Intermediate Company and each Subject Company for the periods presented in accordance with GAAP consistently applied, subject to normal year-end audit adjustments and the absence of footnotes.

(d)     (i) operating reports for each Project covering the years ended December 31, 2011, December 31, 2012, December 31, 2013, December 31, 2014 and December 31, 2015, to the extent applicable, and (ii) operating reports and budgets for each Project as of June 30, 2016 (the reports in clauses (i) and (ii) collectively the “Operating Reports”), in each case in form and substance satisfactory to JPM.

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Section 3.11     Absence of Material Change. Except as set forth on Schedule 3.11, since the date of the Interim Financials, no Subject Company has incurred any liabilities that could reasonably be expected to have a Material Adverse Effect. Except as set forth on Schedule 3.11, since the date of the Interim Financials, the Subject Companies and the Projects (i) have been managed and operated in the Ordinary Course of Business, (ii) have not suffered any damage, destruction or loss in excess of one million dollars ($1,000,000) to any of the Subject Companies or Projects whether or not covered by insurance, (iii) have not made any material changes in accounting systems, policies, principles or practices, or (iv) have not waived, released or cancelled any material claims against any third parties or debts owing to it.

Section 3.12     Compliance with Applicable Law.

(a)     Except as set forth on Schedule 3.12 and other than (i) Environmental Laws (which are addressed in Section 3.13) and (ii) Taxes (which are addressed in Section 3.9), the Company and the Subject Companies are in compliance with Applicable Law in all material respects, and neither the Company nor any of the Subject Companies has received written notice from a Governmental Authority of an actual or potential violation of any Applicable Law.

(b)     Without limiting the generality of the foregoing Section 3.12(a):

(i)     none of ONI, OrLeaf, the Company or any Subject Company, nor any of their respective officers, directors, employees or agents, has (A) violated any provision of any applicable anti-bribery or anti-corruption law including, but not limited to, the U.S. Foreign Corrupt Practices Act of 1977, as amended, or (B) directly or indirectly offered, paid, promised to pay, or authorized the offer, payment or promise of any advantage, financial or otherwise, or thing of value to any representative or agent of a Governmental Authority while knowing or having reason to know that all or a portion of such advantage or thing of value would be offered, given, or promised to such representative or agent of a Governmental Authority for the purposes of (I)(a) influencing any act or decision of any such representative or agent of a Governmental Authority in his or her official capacity or (b) rewarding the improper performance by any Person of its business or official activities; or (II) assisting any member of the Company or any Subject Company in obtaining or retaining business or a business advantage for any member of the Company or any Subject Company;

(ii)     the operations of the Company and each Subject Company have been conducted at all times in compliance with applicable laws relating to financial record keeping and reporting, currency transfer and money laundering, including, as applicable, the US PATRIOT Act of 2001 and all “know your customer” rules and other applicable regulations (collectively with the laws described in clause (A) of Section 3.12(b)(i), “Anti-Corruption Laws”);

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(iii)     the Company and each Subject Company have complied with all U.S. and applicable international economic and trade sanctions and embargoes, including any sanctions or regulations administered and enforced by the U.S. Department of State, the U.S. Department of the Treasury (including the Office of Foreign Assets Control) and any executive orders, rules and regulations relating thereto, collectively, “Sanctions”). Neither the Company nor any Subject Company has engaged in any dealings or transaction with any Person that is on the Office of Foreign Assets Control’s Specially Designated Nations and Blocked Persons List or on any other list of blocked persons maintained by the Office of Foreign Assets Control;

(iv)     the Ormat Guarantor has implemented and maintains in effect policies and procedures designed to ensure compliance by ONI, OrLeaf, the Company and each Subject Company, and their respective directors, officers, employees and agents, with Anti-Corruption Laws and applicable Sanctions;

(v)     none of (a) ONI, OrLeaf, the Company or any Subject Company, nor any of their respective officers, directors, employees or agents, or (b) the Company and the Subject Companies, any agent of ONI, OrLeaf, the Company or any Subject Company that will act in any capacity in connection with or benefit from the transactions contemplated by the Transaction Documents, is a Sanctioned Person; and

(vi)     assuming compliance with Applicable Law by JPM, no part of the transactions contemplated by the Transaction Documents will violate Anti-Corruption Laws or applicable Sanctions.

Section 3.13     Environmental Matters. Except as listed on Schedule 3.13, (i) each Subject Company is, and during the past five (5) years has been, in material compliance with all Environmental Laws and permits issued thereunder, (ii) there are no locations or premises currently or previously owned, leased or used by a Subject Company where, during the period that it or an Affiliate of ONI has owned or operated the relevant Project, Hazardous Substances have been (1) shipped off-site by or for the Subject Company in material violation of Environmental Laws or that require remediation or clean up pursuant to Environmental Laws, or (2) Released in material violation of Environmental Laws, (iii) there has been no material Release of Hazardous Substances at any property currently or, to the Knowledge of any Subject Company, previously owned, leased or used by a Subject Company in connection with the relevant Project that is required or would reasonably be expected to be required to be remediated, abated or otherwise cleaned up pursuant to Environmental Laws, (iv) to ONI’s Knowledge, there are no past actions, circumstances, conditions, events or incidents that could reasonably be expected to form the basis of any material claim against the Company or any Subject Company under any Environmental Laws, and (v) none of ONI, OrLeaf, the Company or the Subject Companies has received written notice from any Governmental Authority or any other Person of an actual or potential material violation of any Environmental Laws or obligation or liability for remediation or clean-up of Hazardous Substances required thereunder.

Section 3.14     Licenses and Permits. Schedule 3.14 lists all material Licenses and Permits necessary for the ownership, operation and maintenance of the Projects. Each of the Licenses and Permits set forth on Schedule 3.14 is in full force and effect and, except as shown on such schedule, is final and non-appealable. The Projects have been constructed in material compliance with all Licenses and Permits and are operating in material compliance with all Licenses and Permits. None of ONI, OrLeaf, the Company or the Subject Companies has received written notice from any Governmental Authority of an actual or potential violation or revocation of any Licenses and Permits that has not been resolved.

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Section 3.15     Insurance. Schedule 3.15 lists all insurance maintained for each Project by or on behalf of the Company or a Subject Company, indicating the types of coverage, name of insurance carrier or underwriter, policy limits and expiration date of each policy. The insurance policies collectively provide full and adequate coverage for all normal risks incident to the properties, assets, management and operations of each Project and the Subject Companies, including without limitation all insurance required under the Material Contracts. Neither the Company nor any of the Subject Companies has had any insurance cancelled or refused by any carrier during the time such Subject Companies have been owned by ONI or its Affiliates. All of the insurance policies are in full force and effect, and neither the Company nor any of the Subject Companies is in default with respect to any obligations it may have under any of the insurance policies in any material respects and premiums with respect to such insurance policies have been paid. None of ONI, Ormat Guarantor, OrLeaf, the Company or the Subject Companies has taken any action that has rendered such insurance unenforceable. There are no unpaid claims on any insurance maintained for each Project.

Section 3.16     Real Property.

(a)     Neither the Company nor the Intermediate Company owns, holds, uses, occupies or leases any real property. All real property owned or leased by each Project Company or to which such Project Company has rights under easements, rights of way, or in which rights are held and the title insurance maintained by such Project Company with respect to all such property, is described on Schedule 3.16. The real property owned or leased, or in which rights are held, by each Project Company, described on Schedule 3.16, have been sufficient to enable each Project Company to conduct its operations as a geothermal power project prior to the Closing Date, including providing adequate ingress and egress and transmission capabilities from each Project and adequate sewer, water, gas and electricity for each Project and these property interests, to the extent applicable, are part of the insured estate in the Title Policies. None of ONI, OrLeaf, the Company or the Subject Companies has been informed in writing by the owner of any such real property that a Project Company is in breach of its obligations with respect to such property. All premiums with respect to the title insurance shown on Schedule 3.16 shall be paid on the Closing Date and, to the Knowledge of the Sellers, there are no circumstances that have rendered such title insurance unenforceable. All rents and royalty obligations under the applicable Material Contracts have been paid in full to the extent due. All utility services necessary for the operation and maintenance of each Project for its intended purpose, including electricity, are available at the boundaries of each Project and either reach such Project through adjoining public real property or, if they pass through adjoining private real property, do so in accordance with the applicable Material Contracts.

(b)     With respect to the real property of each Project site, each Project Company is in compliance in all material respects with all Applicable Law in effect as of the Closing Date pertaining to land use or zoning restrictions.

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Section 3.17     Personal Property. The Company owns no personal property other than the membership interests in the Subject Companies. Schedule 3.17 lists all items of personal property having a replacement cost of at least five hundred thousand dollars ($500,000) owned by each of the Subject Companies. Except as shown on Schedule 3.18, each Subject Company has good and marketable title to its personal property as listed thereon. Each Subject Company owns, leases or has contractual rights to use all the equipment and facilities necessary for the operations of its respective Projects as of the date hereof. The tangible assets included in the Projects are in good condition, free and clear from all defects (patent or latent), taking into account their use and age, subject to normal wear and tear, and subject to continued maintenance, repair and replacement in the ordinary course of business.

Section 3.18     Liens. Except as listed on Schedule 3.18, all assets owned by the Company and by each of the Subject Companies are free and clear of all Liens, other than Permitted Liens.

Section 3.19     Material Contracts. Schedule 3.19 lists all Material Contracts to which the Company and each Subject Company is a party. Each Material Contract is in full force and effect, is a legal, valid and binding obligation of, and enforceable against the Company and the relevant Subject Company, as applicable, and to the Sellers' Knowledge, on the other parties thereto, except as enforceability may be limited by applicable bankruptcy and similar laws affecting the enforcement of creditors’ rights and general equitable principles. Neither the Company nor any Subject Company or, to the Knowledge of the Sellers, any other party to a Material Contract is in default under any Material Contract and no event has occurred which, with notice, lapse of time or action by a third party, would result in such a default under any Material Contract. No party to any of the Material Contracts has exercised any right of termination with respect thereto. True, correct and complete copies of all Material Contracts have been provided to JPM and no Material Contracts have been amended, assigned, terminated or otherwise modified except as disclosed in writing to JPM.

Section 3.20     Consents and Approvals. All material consents, waivers, authorizations, approvals and filings required to be obtained or made by each of the Sellers, the Ormat Guarantor, the Company or any Subject Company (including any third party consents) for the execution, delivery and performance of the Transaction Documents to which it is a party that are being executed at Closing have been obtained or made, have been delivered to JPM and are in full force and effect.

Section 3.21     Employee Matters. Neither the Company nor any Subject Company has any employees and neither the Company nor any Subject Company ever had any employees. Neither the Company nor any Subject Company has maintained, sponsored, administered or participated in any employee benefit plan or arrangement, including any employee benefit plan subject to ERISA.

Section 3.22     Affiliate Transactions. Except as listed on Schedule 3.22 and except for the Transaction Documents, there are no existing contracts between the Company or any Subject Company, on the one hand, and ONI, OrLeaf, or any other Affiliate of ONI, on the other hand. Neither the Company nor any of the Subject Companies has any outstanding debt to an Affiliate thereof (except that the Subject Companies (other than the DAC 2 Project Company) are guarantors of the Existing Indebtedness).

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Section 3.23     QF Status. Each of the Projects has status as a qualifying small power production facility (a “QF”) within the meaning of the Public Utility Regulatory Policies Act of 1978, as amended (“PURPA”), and FERC’s rules and regulations promulgated thereunder, and each of the Projects has obtained and currently possesses qualifying facility status per the FERC’s regulations in 18 C.F.R. § 292.207. Each of the Projects is not currently subject to any pending inquiry, investigation, or challenge relating to its status as a QF. Each of the Projects uses geothermal resources as its primary energy source and each Project Company is exempt under 18 C.F.R. § 292.601 of the FERC’s regulations from the requirements of Section 203(a)(1)(A) of the FPA.

Section 3.24     Intellectual Property. The Company and each of the Subject Companies, through rights granted by ONI and its Affiliates or otherwise, possess all rights necessary to lawfully use all patents, trademarks, licenses, service marks, trade names, trade secrets, and other proprietary, contract or intellectual property rights that are necessary for the operation of the respective Projects and their respective businesses in the Ordinary Course of Business. To the Knowledge of ONI, the operation of the Projects and the businesses as conducted by the Company and each Subject Company does not infringe on any patent, trademark, license, service mark, trade name, trade secret, obligation of confidence or other proprietary, contract, intellectual property or other legally protectable right of any Person.

Section 3.25     Public Utility Holding Company. Neither ONI, OrLeaf, the Company nor any Subject Company is subject to or not exempt from regulation as a “holding company” or a “public utility company” within the meaning of the Public Utility Holding Company Act of 2005 as amended (“PUHCA”).

Section 3.26     Investment Company Act. Neither the Company nor any Subject Company is an “investment company” or company “controlled” by an “investment company” within the meaning of the Investment Company Act of 1940, as amended. In making the preceding representation and warranty, the Sellers are not relying on an exemption under Section 3(c)(1) or 3(c)(7) of the Investment Company Act of 1940.

Section 3.27     No Condemnation. No condemnation is pending or threatened in writing, that is material to the ownership or operation of the Projects.

Section 3.28     No Casualty. No unrepaired casualty exists with respect to any Project or any portion thereof.

Section 3.29     Brokers. Neither the Company nor any Subject Company has retained any broker, agent or finder or incurred any liability or obligation for any brokerage fees, commissions or finder fees with respect to this Agreement or any transactions contemplated under the Transaction Documents that are being executed at Closing.

Section 3.30     Background Materials. The Sellers collected, and with respect to documents prepared by the Sellers, prepared the Background Materials in good faith. Without limiting the effectiveness of any qualification contained in any other representation or warranty in this Article III, the Background Materials constitute all documents and written materials in the Sellers’ possession (and in the possession of the Company and the Subject Companies) containing material information (exclusive of documents that contain information duplicative of information contained or incorporated in any other Background Materials) relating to the Company, the Projects and the Subject Companies, and the Background Materials, when taken as a whole, do not contain any untrue statement of a material fact concerning the Company or the Projects or the Subject Companies and the transactions contemplated by this Agreement. Neither Seller has knowingly omitted any material fact from the Background Materials, which would be necessary to make the statements and information contained in the Background Materials, when taken in their entirety, not misleading. Notwithstanding anything in this Section 3.30, no representation or warranty is made with respect to any Background Materials that are in the nature of projections other than that (i) they were prepared in good faith and on the basis of assumptions that were considered reasonable by the Sellers at the time made, and (ii) to the extent prepared on or after September 30, 2016 (which the Sellers acknowledge includes the Base Case Model), the Sellers continue to consider to be reasonable in all material respects.

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Section 3.31     No Other Representations. JPM has not made any representations or warranties, either express or implied, nor have the Sellers relied on any representations or warranties whatsoever, express, implied, at common law, statutory or otherwise, except for the representations and warranties of JPM expressly set out in this Agreement and, when executed and delivered, the Transaction Documents to which it is a party, and any certification or document delivered in connection with any of the foregoing.

Article IV
REPRESENTATIONS AND WARRANTIES OF JPM

JPM represents and warrants to the Sellers as of the Closing Date, as follows:

Section 4.1     Organization, Good Standing, Etc. JPM is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware, and has the corporate power and authority to own, lease and operate its properties and to carry on its business as being conducted on the date hereof.

Section 4.2     Authority. JPM has the necessary power and authority to enter into this Agreement and the other Transaction Documents to which it is a party, to perform its obligations hereunder and thereunder, and to consummate the transactions contemplated hereby or thereby. All corporate actions or proceedings required to be taken by or on the part of JPM to authorize and permit the due execution and valid delivery by JPM of this Agreement and the instruments required to be duly executed and validly delivered by JPM pursuant hereto and thereto, the performance by JPM of its obligations hereunder and thereunder, and the consummation by JPM of the transactions contemplated herein and therein, have been duly and properly taken. This Agreement has been duly executed and validly delivered by JPM and constitutes the legal, valid and binding obligation of JPM, enforceable in all material respects against JPM in accordance with its terms, except as such enforceability (i) may be limited by applicable bankruptcy, insolvency, reorganization, fraudulent conveyance, moratorium or other similar laws affecting the enforcement of creditors’ rights and remedies generally and (ii) is subject to general principles of equity (regardless of whether enforceability is considered in a proceeding in equity or at law).

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Section 4.3     No Conflicts. The execution and delivery by JPM of this Agreement and the other Transaction Documents to which JPM is a party do not, and the performance by JPM of JPM obligations hereunder and thereunder will not, (i) violate any Applicable Law, (ii) conflict with or cause a breach of any provision of its Organizational Documents, (iii) cause a breach of, constitute a default under, cause the acceleration of, create in any party the right to accelerate, terminate, modify or cancel, or require any authorization, consent, waiver or approval under any contract, license, instrument, decree, judgment or other arrangement to which JPM is a party or under which it is bound or to which any of its assets are subject (or result in the imposition of a Lien upon any such assets) or (iv) except as otherwise described in Schedule 4.3, require any notice to, filing with, or authorization, consent or approval of, any Governmental Authority.

Section 4.4     Absence of Litigation. No pending or outstanding injunction, judgment, order, decree, ruling or charge is pending against JPM and, to the knowledge of JPM, JPM is not threatened with being made a party to any action, suit, proceeding, hearing or investigation of, in, or before any Governmental Authority or before any arbitrator that could affect its ability to complete the transactions contemplated in the Transaction Documents to which it is a party.

Section 4.5     Information and Due Diligence. Without limiting any rights and remedies available to JPM under this Agreement or at law, JPM acknowledges that it has had a reasonable opportunity to ask questions of and receive answers from the Sellers concerning ONI, the Class B Membership Interest, the Company and the Subject Companies, and has received or been given access to documents and information requested from the Sellers. JPM (i) acknowledges that investment in the Class B Membership Interest involves substantial risks, (ii) acknowledges that any financial projections that may have been provided to it are based on assumptions of future operating results developed by the Sellers and the Sellers' advisers and, therefore, represent an estimate of future results based on assumptions about certain events (many of which are beyond the control of ONI, OrLeaf, the Company and the Subject Companies), and (iii) understands that no assurances or representations can be given that the actual results of the operations of the Company and the Subject Companies will conform to the projected results for any period. JPM has not relied on the advice of ONI, OrLeaf or the Company or any of their respective legal, tax or financial advisers in making an investment in the Class B Membership Interests. Notwithstanding the foregoing, nothing contained in this Section 4.5 shall modify or negate any representations or warranties made by the Sellers herein or preclude reliance thereon by JPM.

Section 4.6     Information and Investment Intent. JPM is an “Accredited Investor” as such term is defined in Regulation D under the Securities Act of 1933. JPM understands that the Class B Membership Interests have not been registered under the Securities Act in reliance on an exemption therefrom, and that the Class B Membership Interest must be held indefinitely unless the sale thereof is registered under the Securities Act or an exemption from registration is available thereunder, and that the Sellers are under no obligation to register the Class B Membership Interest. JPM is acquiring the Class B Membership Interest for its own account and not for the account of any other Person and not with a view to distribution to others.

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Section 4.7     Security Interest. JPM has not pledged or otherwise encumbered any right, title or interest in or to the Class B Membership Interest.

Section 4.8     Public Utility Holding Company. JPM is not subject to regulation as a “holding company” or a “public utility company” within the meaning of PUHCA.

Section 4.9     No Other Seller Representations. The Sellers have not made any representations or warranties, either express or implied, nor has JPM relied on any representations or warranties whatsoever, express, implied, at common law, statutory or otherwise, except for the representations and warranties of the Sellers expressly set out in this Agreement and the representations or warranties of any of ONI, OrLeaf, the Company, the Subject Companies and the Ormat Guarantor expressly set out in, when executed and delivered, the Transaction Documents to which it is a party, and any certification or document delivered in connection with any of the foregoing.

Section 4.10     Tax Matters. JPM is (i) a “United States person” within the meaning of Section 7701(a)(30) of the Code; (ii) not a “tax-exempt entity” within the meaning of Section 168(h) of the Code; and (iii) an Unrelated Person.

Article V
TAX MATTERS

Section 5.1     Transfer Taxes. Any transfer, documentary, sales, use, real property transfer, recording, gains, registration and other similar taxes and fees (“Transfer Taxes”) incurred in connection with the transfer of the Class B Membership Interests to JPM pursuant to this Agreement shall be borne by OrLeaf, and OrLeaf, at its own expense, shall file or cause to be filed (to the extent required or permitted by Applicable Law) all necessary Tax Returns and other documentation with respect to all such Transfer Taxes.

Section 5.2     Pre-Closing Date Tax Return Preparation. OrLeaf will prepare or cause to be prepared and timely file or cause to be timely filed all Tax Returns for the Company and the Subject Companies for all periods ending on or prior to the Effective Date (the “Pre-Closing Tax Period”) that are filed after such Effective Date and will timely pay or cause to be timely paid all Taxes shown to be due on such Tax Returns if the amount shown to be due is not included in the Base Case Model. All such Tax Returns shall be prepared in a manner consistent with past practice unless otherwise required by a change in Applicable Law. OrLeaf will permit JPM to review and comment on each such Tax Return described in the preceding sentence prior to filing and will consider in good faith any revisions to such Tax Returns as are reasonably requested by JPM.

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Section 5.3     Tax Periods Beginning Before the Effective Date. OrLeaf shall pay and indemnify and hold harmless the Company, the Subject Companies, and JPM for any Taxes in respect of periods (or portions thereof) ending prior to the Closing Date to the extent that such items are not included in the Base Case Model. For purposes of this Section 5.3, all Taxes and Tax liabilities with respect to the income, property or operations of the Company and the Subject Companies that relate to any taxable period that includes (but does not end on) the Effective Date shall be apportioned between the portion of the Straddle Period ending on and including the Effective Date and the applicable Tax period thereafter as follows: (A) in the case of Taxes (other than income, sales and use and withholding and other transactional Taxes), on a per diem basis and (B) in the case of income, sales and use and withholding and other transactional Taxes, as determined from the books and records of the Company and the Subject Companies as though the taxable year of such entity terminated at the close of business on the Effective Date. For purposes of clause (B), (i) any credits relating to a taxable period that begins before and ends after the Effective Date will be taken into account as though the relevant Tax period ended on the Effective Date, and (ii) any item determined on an annual or periodic basis (including amortization and depreciation deductions and credits) shall be allocated to the portion of the Straddle Period ending on the Effective Date based on the relative number of days in such portion of the Straddle Period as compared to the number of days in the entire Straddle Period. All determinations necessary to give effect to the foregoing allocations will be made in a manner consistent with prior practice of the Company and the Subject Companies. For the avoidance of doubt, OrLeaf shall be responsible for all Taxes in respect of periods (or portions thereof) ending prior to the Closing Date not reflected in the Base Case Model unless incorrect due to a change in Applicable Law after the Closing Date. OrLeaf shall have the right to represent the Company and the Subject Companies with respect to any Tax claims or audits with respect to all Tax Return and Taxes that OrLeaf is required to file or pay pursuant to Section 5.2 and 5.3; provided, however, that with respect to any such Tax claims or audits, (i) OrLeaf shall keep JPM reasonably and timely informed with respect to the commencement, status and nature of any such Tax claim or audit, (ii) JPM shall have the right to participate in any such Tax claim or audit at the Company’s reasonable expense if such participation is reasonably necessary to protect JPM’s interests, and (iii) OrLeaf shall not settle any such Tax claims or audits, if such settlement could reasonably be expected to have an adverse effect on the Company, any Subject Company or JPM or subject any of the foregoing to Taxes for a period following the Effective Date, without the consent of JPM, which consent shall not be unreasonably withheld, conditioned or delayed; provided; however; nothing in this Section 5.3 is intended to supersede the tax contest provisions set forth in the Company LLC Agreement.

Section 5.4     Refunds and Tax Benefits; Amended Tax Returns. Any Tax refunds that are received by JPM, the Company or any Subject Company and any amounts credited against Tax to which JPM, the Company or any Subject Company become entitled, that relate to a Pre-Closing Tax Period (or portion of a Straddle Period ending on the Effective Date as determined in accordance with the same principals provided for in Section 5.3) and that were paid prior to the Effective Date or paid by OrLeaf under Sections 5.2 or 5.3 will be for the account of OrLeaf, and the Company or the applicable Subject Company will pay over to OrLeaf any such refund or the amount of any such credit within fifteen (15) days after receipt or entitlement thereto; provided, however, that the Company or any Subject Company, as applicable, shall be entitled to any refund of Property Taxes of the Company or such Subject Company due after the Effective Date and paid by the Company or such Subject Company (unless OrLeaf has otherwise indemnified JPM). Without limiting the generality of the foregoing, this Section 5.4 will apply to any sales Tax rebates and refunds, Property Tax exemption and credits or reductions in Property Taxes attributable to a retroactive reduction in assessment rate or assessment base. No amended Tax Return or action for Tax refund may be filed for any Tax Returns of the Company or any the Subject Company for a Pre-Closing Tax Period or Straddle Period without the advance written consent of OrLeaf, the Company or any applicable Subject Company.

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Section 5.5     Cooperation on Tax Matters.

(a)     The Parties will cooperate fully, as and to the extent reasonably requested by the other Party, in connection with the filing of Tax Returns pursuant to this Article V and any audit, litigation or other action with respect to Taxes. Such cooperation will include the retention and (upon the other Party’s request) the provision of records and information that are reasonably relevant to any such audit, litigation or other action and making employees available on a mutually convenient basis to provide additional information and explanation of any material provided hereunder. The Parties agree (to the extent such books and records are within their possession) (A) to retain all books and records with respect to Tax matters pertinent to the Company and the Subject Companies relating to any taxable period beginning before the Effective Date until the expiration of the statute of limitations (and, to the extent notified by JPM, any extensions thereof) of the respective taxable periods, and to abide by all record retention agreements entered into with any Taxing authority and (B) to give the other party reasonable written notice prior to transferring, destroying or discarding any such books and records and, if the other party so requests, OrLeaf will allow the other party to take possession of such books and records.

(b)     The Parties further agree, upon request, to use reasonable efforts to obtain any certificate or other document from any Governmental Authority or any other Person as may be necessary to mitigate, reduce or eliminate any Tax that could be imposed (including without limitation with respect to the transactions contemplated by this Agreement).

Article VI
CERTAIN OTHER COVENANTS

Section 6.1     Confidentiality. The Confidentiality Agreement, dated March 12, 2015, between ONI and JPM (the “Confidentiality Agreement”) shall terminate at the Effective Time and, thereafter, the provisions of Section 13.12 of the Company LLC Agreement shall apply with respect to the confidentiality obligations of the Parties.

Section 6.2     Intellectual Property. Following the Effective Time and during the term of the Company LLC Agreement, the Sellers shall make available, or cause their Affiliates to make available, to the Company and each of the Subject Companies all rights necessary to lawfully use all patents, trademarks, licenses, service marks, trade names, trade secrets, and other proprietary, contract or intellectual property rights that are necessary for the operation of the respective Projects and their respective businesses in the Ordinary Course of Business, on terms and conditions no less favorable to the Company and the Subject Companies than those applicable prior to the Effective Time.

Section 6.3     Licenses and Permits; Material Contracts. Within thirty (30) Business Days after the Closing, OrLeaf shall deliver to JPM a compact disc containing copies of each License and Permit and each Material Contract required to be delivered on the Closing Date hereunder.

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Article VII
INDEMNIFICATION

Section 7.1     Indemnification. OrLeaf agrees to indemnify, defend and hold harmless Class B Member Indemnified Parties from and against any and all Class B Member Indemnified Costs, pursuant to Article XI of the Company LLC Agreement.

Article VIII
GENERAL PROVISIONS

Section 8.1     Exhibits and Schedules; Headings. All Exhibits and Schedules attached hereto are incorporated herein by reference. The headings of Articles and Sections in this Agreement are provided for convenience only and will not affect its construction or interpretation.

Section 8.2     Disclosure Schedules. Any matter disclosed in any section of the Schedules shall be deemed disclosed for all purposes and all sections of the Schedules, to the extent it is readily apparent from a reading of the disclosure that such disclosure is applicable to such other sections.

Section 8.3     Amendment, Modification and Waiver. This Agreement may not be amended or modified except by an instrument in writing signed by the Parties. Any failure of JPM or the Sellers to comply with any obligation, covenant, agreement, or condition contained herein may be waived only if set forth in an instrument in writing signed by the Party to be bound thereby, but such waiver or failure to insist upon strict compliance with such obligation, covenant, agreement or condition shall not operate as a waiver of, or estoppel with respect to, any other failure.

Section 8.4     Severability. If any term or other provision of this Agreement is invalid, illegal, or incapable of being enforced by any rule of Applicable Law, or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated herein are not affected in any manner materially adverse to any Party.

Section 8.5     Survival. The representations, warranties, and indemnities in this Agreement shall survive in accordance with the express survival periods provided in the Company LLC Agreement.

Section 8.6     Expenses. ONI will be responsible for all the costs, fees and expenses in connection with the preparation, negotiation and consummation of the transactions contemplated by this Agreement and the other Transaction Documents, whether or not the Closing occurs (collectively, the “Transaction Expenses”). No Party shall be responsible for any commission, broker’s fee, finder’s fee or similar fee or expense of any other Party.

Section 8.7     Parties in Interest. This Agreement shall be binding upon and, except as provided below, inure solely to the benefit of each Party and their successors and permitted assigns, and nothing in this Agreement, express or implied, is intended to confer upon any other Person any rights or remedies of any nature whatsoever under or by reason of this Agreement.

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Section 8.8     Notices. All notices and other communications hereunder shall be in writing and shall be deemed given if delivered personally, by a nationally recognized overnight courier, by facsimile (confirmed receipt), or mailed by registered or certified mail (return receipt requested) to the Parties at the following addresses (or at such other address for a Party as shall be specified by like notice):

(a)          If to ONI, to:

Ormat Nevada Inc.
6225 Neil Road
Reno, Nevada 89511
Attention:       CFO
Telephone:     (775) 356-9029
Facsimile:      (775) 356-9039

With a copy to:

Chadbourne & Parke LLP
1200 New Hampshire Avenue, NW
Washington, DC 20036
Attention:      Noam Ayali
Telephone:    (202) 974-5600
Facsimile:      (202) 974-5602

(b) If to OrLeaf:

OrLeaf LLC

c/o Ormat Nevada Inc.
6225 Neil Road
Reno, Nevada 89511
Attention:       CFO
Telephone:     (775) 356-9029
Facsimile:      (775) 356-9039

With a copy to:

Chadbourne & Parke LLP
1200 New Hampshire Avenue, NW
Washington, DC 20036
Attention:       Noam Ayali
Telephone:     (202) 974-5600
Facsimile:      (202) 974-5602

(c)          If to JPM, to:

JPM Capital Corporation
Mail Code ILl-0502
10 South Dearborn, 12th Floor
Chicago, Illinois 60603-2300
Attention:      Anand Dandapani
Telephone:    (312) 732-3119
Facsimile:      (312) 336-3550

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All notices and other communications given in accordance herewith shall be deemed given (i) on the date of delivery, if hand delivered, (ii) on the date of confirmed receipt, if faxed (provided a hard copy of such transmission is dispatched by first class mail within 48 hours), (iii) 3 Business Days after the date of mailing, if mailed by registered or certified mail, return receipt requested, and (iv) 1 Business Day after the date of sending, if sent by a nationally recognized overnight courier; provided, that a notice given in accordance with this Section 8.8 but received on any day other than a Business Day or after business hours in the place of receipt, will be deemed given on the next Business Day in that place.

Section 8.9     Counterparts. This Agreement may be executed and delivered (including by facsimile or other electronic transmission) in one or more counterparts, all of which shall be considered one and the same agreement and shall become effective when one or more counterparts have been signed by each of the Parties and delivered to the other Party, it being understood that all Parties need not sign the same counterpart.

Section 8.10     Entire Agreement. This Agreement (together with the other Transaction Documents executed as of the date hereof) constitutes the entire agreement of the Parties and supersedes all prior agreements, letters of intent and understandings, both written and oral, among the Parties with respect to the subject matter hereof.

Section 8.11     Governing Law; Choice of Forum; Waiver of Jury Trial. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW (OTHER THAN SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW, WHICH SHALL APPLY TO THIS AGREEMENT). THE PARTIES HEREBY IRREVOCABLY SUBMIT TO THE NON-EXCLUSIVE JURISDICTION OF ANY STATE OR FEDERAL COURT IN NEW YORK WITH RESPECT TO ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT. EACH PARTY HEREBY WAIVES ANY RIGHT IT MAY HAVE TO ASSERT THE DOCTRINE OF FORUM NON CONVENIENS OR SIMILAR DOCTRINE OR TO OBJECT TO VENUE WITH RESPECT TO ANY PROCEEDING BROUGHT IN ACCORDANCE WITH THIS SECTION 8.11, AND STIPULATES THAT THE STATE AND FEDERAL COURTS LOCATED IN THE STATE OF NEW YORK, SHALL HAVE IN PERSONAM JURISDICTION OVER EACH OF THEM FOR THE PURPOSE OF LITIGATING ANY SUCH DISPUTE, CONTROVERSY, OR PROCEEDING. EACH PARTY HEREBY AUTHORIZES AND ACCEPTS SERVICE OF PROCESS SUFFICIENT FOR PERSONAL JURISDICTION IN ANY ACTION AGAINST IT AS CONTEMPLATED BY THIS SECTION 8.11 BY REGISTERED OR CERTIFIED MAIL, RETURN RECEIPT REQUESTED, POSTAGE PREPAID, TO ITS ADDRESS FOR THE GIVING OF NOTICES AS SET FORTH IN SECTION 8.8. NOTHING HEREIN SHALL AFFECT THE RIGHT OF ANY PARTY TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY LAW. EACH PARTY HERETO IRREVOCABLY AND UNCONDITIONALLY WAIVES TRIAL BY JURY IN ANY ACTION, SUIT OR PROCEEDING RELATING TO A DISPUTE AND FOR ANY COUNTERCLAIM WITH RESPECT THERETO.

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Section 8.12     Attorneys’ Fees. If suit or action is filed by any Party to enforce the provisions of this Agreement or otherwise with respect to the subject matter of this Agreement or the transactions contemplated hereby, the prevailing Party shall be entitled to recover reasonable attorneys’ fees related thereto (as the prevailing Party and the amount of recoverable attorney’s fees are determined by a court of competent jurisdiction in a final non-appealable order).

Section 8.13     Public Announcements. Except for statements made or press releases issued (i) pursuant to the Securities Act of 1933 or the Securities Exchange Act of 1934, (ii) pursuant to any listing agreement with any national securities exchange or the National Association of Securities Dealers, Inc., or (iii) as otherwise required by law, neither the Sellers nor JPM shall issue, or permit any of their respective Affiliates to issue, any press release or otherwise make any public statements with respect to this Agreement or the transactions contemplated hereby without the prior written consent of the other Party. The Sellers and JPM will have the right to review in advance all information relating to the transactions contemplated by the Transaction Documents executed as of the date hereof that appear in any filing made in connection with the transactions contemplated hereby or thereby.

Section 8.14     Further Assurances. Upon the reasonable request of a Party or Parties hereto at any time after the Closing Date, the other Party or Parties shall forthwith execute and deliver such further instruments of assignment, transfer, conveyance, endorsement, direction or authorization and other documents as the requesting Party or Parties or its or their counsel may reasonably request in order to effectuate the purposes of this Agreement.

Section 8.15     Assignment. This Agreement and all of the provisions hereof will be binding upon and inure to the benefit of the Parties and their respective successors and permitted assigns. This Agreement may only be assigned to the same extent (and only by and to the same Persons) that membership interests in the Company are assignable pursuant to the terms of the Company LLC Agreement. Any attempted assignment of this Agreement other than in strict accordance with this Section and the terms of the Company LLC Agreement shall be null and void and of no force or effect.

Section 8.16     Relationship of Parties; No Strict Construction. This Agreement does not constitute a joint venture, association or partnership between the Parties. No express or implied term, provision or condition of this Agreement shall create, or shall be deemed to create, an agency, joint venture, partnership or any fiduciary relationship between the Parties. The Transaction Documents are the result of negotiations among, and have been reviewed by JPM, the Sellers and the Company, and their respective counsel. Accordingly, the Transaction Documents shall be deemed to be the product of all of the Parties, and no ambiguity shall be construed in favor of or against JPM or the Sellers.

[Remainder of page intentionally left blank. Signature pages to follow.]

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IN WITNESS WHEREOF, each Party hereto has caused this Equity Contribution Agreement to be signed on its behalf as of the date first written above.

ORMAT NEVADA INC.

By: /s/ Connie Stechman                                               
Name: Connie Stechman
Title: Secretary

OrLeaf, LLC

By: Ormat Nevada Inc., as its managing member

By: /s/ Connie Stechman                                                
Name: Connie Stechman
Title: Secretary

[SIGNATURE PAGE TO EQUITY CONTRIBUTION AGREEMENT]

IN WITNESS WHEREOF, each Party hereto has caused this Equity Contribution Agreement to be signed on its behalf as of the date first written above.

JPM CAPITAL CORPORATION

By: /s/ Anand Dandapani                                                
Name: Anand Dandapani
Title: Executive Director

[SIGNATURE PAGE TO EQUITY CONTRIBUTION AGREEMENT]

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Registration Nos. 333-129583, 333-143488 and 333-181509) of Ormat Technologies, Inc. of our report dated March 1, 2017 relating to the consolidated financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

San Francisco, California

March 1, 2017

EX-31.1

Exhibit 31.1

Ormat Technologies, Inc.

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Isaac Angel, certify that:

1. I have reviewed this annual report on Form 10-K of Ormat Technologies, 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.

By:	/s/ Isaac Angel
Name:	Isaac Angel
Title:	Chief Executive Officer

Date: March 1, 2017

EX-31.2

Exhibit 31.2

Ormat Technologies, Inc.

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Doron Blachar, certify that:

1. I have reviewed this annual report on Form 10-K of Ormat Technologies, 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.

By:	/s/ DORON BLACHAR
Name:	Doron Blachar
Title:	Chief Financial Officer

Date: March 1, 2017

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Isaac Angel, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the annual report of Ormat Technologies, Inc. on Form 10-K for the year ended December 31, 2016 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such annual report on Form 10-K fairly presents in all material respects the financial condition, results of operations and cash flows of Ormat Technologies, Inc. as of and for the periods presented in such annual report on Form 10-K. This written statement is being furnished to the Securities and Exchange Commission as an exhibit accompanying such annual report and shall not be deemed filed pursuant to the Securities Exchange Act of 1934.

By:	/s/ Isaac Angel
Name:	Isaac Angel
Title:	Chief Executive Officer

Date: March 1, 2017

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Doron Blachar, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the annual report of Ormat Technologies, Inc. on Form 10-K for the year ended December 31, 2016 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such annual report on Form 10-K fairly presents in all material respects the financial condition, results of operations and cash flows of Ormat Technologies, Inc. as of and for the periods presented in such annual report on Form 10-K. This written statement is being furnished to the Securities and Exchange Commission as an exhibit accompanying such annual report and shall not be deemed filed pursuant to the Securities Exchange Act of 1934.

By:	/s/ DORON BLACHAR
Name:	Doron Blachar
Title:	Chief Financial Officer

Date: March 1, 2017

XML

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 27, 2017	Jun. 30, 2016
Document Information [Line Items]
Entity Registrant Name	ORMAT TECHNOLOGIES, INC.
Entity Central Index Key	0001296445
Trading Symbol	ora
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Entity Common Stock, Shares Outstanding (in shares)		49,667,340
Entity Public Float			$ 1,418,095,165
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Amendment Flag	false

XML

Consolidated Balance Sheets - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents		$ 230,214	$ 185,919
Restricted cash and cash equivalents		34,262	49,503
Receivables:
Trade		80,807	55,301
Other		17,482	7,885
Inventories		12,000	18,074
Costs and estimated earnings in excess of billings on uncompleted contracts		52,198	25,120
Prepaid expenses and other		45,867	33,334
Total current assets		472,830	375,136
Deposits and other		18,553	17,968
Deferred charges		43,773	42,811
Property, plant and equipment, net		1,556,378	1,559,335
Construction-in-process		306,709	248,835
Deferred financing and lease costs, net		3,923	4,022
Intangible assets, net		52,753	25,875
Goodwill		6,650
Total assets	[1]	2,461,569	2,273,982
Current liabilities:
Accounts payable and accrued expenses		91,650	91,955
Billings in excess of costs and estimated earnings on uncompleted contracts		31,630	33,892
Current portion of long-term debt:
Senior secured notes		32,234	29,930
Other loans		21,495	21,495
Full recourse		12,242	11,229
Total current liabilities		189,251	188,501
Long-term debt, net of current portion:
Senior secured notes (less deferred financing costs of $9,177 and $10,852, respectively)		350,388	294,476
Other loans (less deferred financing costs of $6,409 and $7,492, respectively)		261,845	275,888
Senior unsecured bonds (plus unamortized premium based upon 7% of $0 and $513, respectively and less deferred financing costs of $755 and $283, respectively)		203,577	249,698
Other loans (less deferred financing costs of $1,346 and $435, respectively)		57,063	18,687
Accumulated losses of unconsolidated company in excess of investment		11,081	8,100
Liability associated with sale of tax benefits		54,662	11,665
Deferred lease income		54,561	58,099
Deferred income taxes		35,382	32,654
Liability for unrecognized tax benefits		5,738	10,385
Liabilities for severance pay		18,600	19,323
Asset retirement obligation		23,348	20,856
Other long-term liabilities		21,294	1,776
Total liabilities		1,286,790	1,190,108
Commitments and contingencies (Note 23)
Redeemable nonconrolling interest		4,772
Equity:
Common stock, par value $0.001 per share; 200,000,000 shares authorized; 49,667,340 and 49,107,901 shares issued and outstanding as of December 31, 2016 and December 31, 2015, respectively		50	49
Additional paid-in capital		869,463	849,223
Retained earnings		216,644	148,396
Accumulated other comprehensive income (loss)		(7,732)	(7,667)
		1,078,425	990,001
Noncontrolling interest		91,582	93,873
Total equity		1,170,007	1,083,874
Total liabilities and equity		$ 2,461,569	$ 2,273,982

[1] Including unconsolidated investments

XML

Consolidated Balance Sheets (Parentheticals) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Property, plant and equipment, net	$ 1,556,378	$ 1,559,335
Construction-in-process	$ 306,709	$ 248,835
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized (in shares)	200,000,000	200,000,000
Common stock, shares issued (in shares)	49,667,340	49,107,901
Common stock, shares outstanding (in shares)	49,667,340	49,107,901
Senior Secured Notes [Member]
Deferred financing costs	$ 9,177	$ 10,852
Other Loans, Limited and Non-recourse [Member]
Deferred financing costs	6,409	7,492
Senior Unsecured Bonds [Member]
Deferred financing costs	$ 755	$ 283
Senior unsecured bonds	7.00%	7.00%
Senior unsecured bonds unamortized premium	$ 0	$ 513
Other Loans, Full Recourse [Member]
Deferred financing costs	1,346	435
Variable Interest Entity, Primary Beneficiary [Member]
Property, plant and equipment, net	1,483,224	1,481,258
Construction-in-process	$ 120,853	$ 129,165

XML

Consolidated Statements of Operations and Comprehensive Income (Loss) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Electricity	$ 436,292	$ 375,920	$ 382,301
Product	226,299	218,724	177,223
Total revenues	662,591	594,644	559,524
Cost of revenues:
Electricity	261,573	242,612	246,630
Product	130,223	133,753	109,143
Total cost of revenues	391,796	376,365	355,773
Gross profit	270,795	218,279	203,751
Operating expenses:
Research and development expenses	2,762	1,780	783
Selling and marketing expenses	16,424	16,077	15,425
General and administrative expenses	46,710	34,782	28,614
Write-off of unsuccessful exploration activities	3,017	1,579	15,439
Operating income	201,882	164,061	143,490
Other income (expense):
Interest income	971	297	312
Interest expense, net	(67,389)	(72,577)	(84,654)
Derivatives and foreign currency transaction gains (losses)	(5,534)	(1,622)	(5,839)
Income attributable to sale of tax benefits	16,503	25,431	24,143
Gain from sale of property, plant and equipment			7,628
Other non-operating income (expense), net	(5,345)	(1,991)	756
Income from continuing operations before income taxes and equity in losses of investees	141,088	113,599	85,836
Income tax (provision) benefit	(31,837)	15,258	(27,608)
Equity in losses of investees, net	(7,735)	(5,508)	(3,213)
Income from continuing operations	101,516	123,349	55,015
Net income attributable to noncontrolling interest	(7,586)	(3,776)	(833)
Net income attributable to the Company's stockholders	93,930	119,573	54,182
Comprehensive income:
Net income	101,516	123,349	55,015
Other comprehensive income (loss), net of related taxes:
Currency translation adjustments	(1,648)
Change in unrealized gains or losses in respect of the Company's share in derivatives instruments of unconsolidated investment	1,185	1,028	(8,112)
Loss in respect of derivative instruments designated for cash flow hedge	87	91	(902)
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge	(96)	(118)	(141)
Comprehensive income	101,044	124,350	45,860
Comprehensive income attributable to noncontrolling interest	(7,179)	(3,776)	(833)
Comprehensive income attributable to the Company's stockholders	$ 93,865	$ 120,574	$ 45,027
Basic:
Net income (in dollars per share)	$ 1.90	$ 2.46	$ 1.19
Diluted:
Net income (in dollars per share)	$ 1.87	$ 2.43	$ 1.18
Weighted average number of shares used in computation of earnings per share attributable to the Company's stockholders:
Basic (in shares)	49,469	48,562	45,508
Diluted (in shares)	50,140	49,187	45,859
Dividend per share declared (in dollars per share)	$ 0.52	$ 0.26	$ 0.21

XML

Consolidated Statements of Equity - USD ($) shares in Thousands, $ in Thousands	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	AOCI Attributable to Parent [Member]	Parent [Member]	Noncontrolling Interest [Member]	Total
Other comprehensive income (loss), net of related taxes:
Balance (in shares)	45,461
Balance (in shares) at Dec. 31, 2013	45,461
Balance at Dec. 31, 2013	$ 46	$ 735,295	$ (3,088)	$ 487	$ 732,740	$ 12,371	$ 745,111
Stock-based compensation		5,571			5,571		5,571
Exercise of options by employees and directors (in shares)	76
Exercise of options by employees and directors		981			981		981
Cash paid to non controlling interest						(651)	(651)
Cash dividend declared			(9,555)		(9,555)		(9,555)
Increase in noncontrolling interest in ORTP LLC						257	257
Acquisition of noncontrolling interest in Crump		159			159	(987)	(828)
Net income (loss)			54,182		54,182	833	55,015
Other comprehensive income (loss), net of related taxes:
Loss in respect of derivative instruments designated for cash flow hedge				(902)	(902)		(902)
Change in unrealized gains or losses in respect of the Company's share in derivatives instruments of unconsolidated investment				(8,112)	(8,112)		(8,112)
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge				(141)	(141)		(141)
Balance (in shares) at Dec. 31, 2014	45,537
Balance at Dec. 31, 2014	$ 46	742,006	41,539	(8,668)	774,923	11,823	786,746
Other comprehensive income (loss), net of related taxes:
Stock-based compensation		5,571			5,571		5,571
Exercise of options by employees and directors (in shares)	76
Exercise of options by employees and directors		981			981		981
Cash paid to non controlling interest						(651)	(651)
Cash dividend declared			(9,555)		(9,555)		(9,555)
Net income (loss)			54,182		54,182	833	55,015
Balance (in shares)	45,461
Increase in noncontrolling interest in ORTP LLC						257	257
Currency translation adjustments
Balance (in shares)	45,537
Stock-based compensation		3,955			3,955		3,955
Exercise of options by employees and directors (in shares)	574
Exercise of options by employees and directors		6,085			6,085		6,085
Cash paid to non controlling interest						(7,196)	(7,196)
Cash dividend declared			(12,716)		(12,716)		(12,716)
Net income (loss)			119,573		119,573	3,776	123,349
Loss in respect of derivative instruments designated for cash flow hedge				91	91		91
Change in unrealized gains or losses in respect of the Company's share in derivatives instruments of unconsolidated investment				1,028	1,028		1,028
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge				(118)	(118)		(118)
Balance (in shares) at Dec. 31, 2015	49,107
Balance at Dec. 31, 2015	$ 49	849,223	148,396	(7,667)	990,001	93,873	1,083,874
Other comprehensive income (loss), net of related taxes:
Stock-based compensation		3,955			3,955		3,955
Exercise of options by employees and directors (in shares)	574
Exercise of options by employees and directors		6,085			6,085		6,085
Share exchange with Parent (Note 2) (in shares)	2,996
Share exchange with Parent (Note 2)	$ 3	26,012			26,015		26,015
Cash paid to non controlling interest						(7,196)	(7,196)
Cash dividend declared			(12,716)		(12,716)		(12,716)
Issuance of shares to noncontrolling interest, net of transaction costs		71,165			71,165	85,470	156,635
Net income (loss)			119,573		119,573	3,776	123,349
Balance (in shares)	45,537
Currency translation adjustments
Balance (in shares)	49,107
Stock-based compensation		5,157			5,157		5,157
Exercise of options by employees and directors (in shares)	560
Exercise of options by employees and directors	$ 1	7,249			7,250		7,250
Cash paid to non controlling interest						(57,391)	(57,391)
Cash dividend declared			(25,682)		(25,682)		(25,682)
Increase in noncontrolling interest in ORTP LLC						3,697	3,697
Net income (loss)			93,930		93,930	7,302	101,516
Loss in respect of derivative instruments designated for cash flow hedge				87	87		87
Change in unrealized gains or losses in respect of the Company's share in derivatives instruments of unconsolidated investment				1,185	1,185		1,185
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge				(96)	(96)		(96)
Balance (in shares) at Dec. 31, 2016	49,667
Balance at Dec. 31, 2016	$ 50	869,463	216,644	(7,732)	1,078,425	91,582	1,170,007
Other comprehensive income (loss), net of related taxes:
Stock-based compensation		5,157			5,157		5,157
Exercise of options by employees and directors (in shares)	560
Exercise of options by employees and directors	$ 1	7,249			7,250		7,250
Cash paid to non controlling interest						(57,391)	(57,391)
Cash dividend declared			(25,682)		(25,682)		(25,682)
Issuance of shares to noncontrolling interest, net of transaction costs		7,834			7,834	36,268	44,102
Net income (loss)			93,930		93,930	7,302	101,516
Balance (in shares)	49,107
Increase in noncontrolling interest in Guadeloupe						8,240	8,240
Increase in noncontrolling interest in ORTP LLC						3,697	3,697
Currency translation adjustments				$ (1,241)	$ (1,241)	$ (407)	$ (1,648)
Balance (in shares)	49,667

XML

Consolidated Statements of Equity (Parentheticals) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Retained Earnings [Member]
Cash dividend declared, per share (in dollars per share)	$ 0.52	$ 0.26	$ 0.21
Loss in respect of derivative instruments designated for cash flow hedge, related tax	$ 54	$ 56	$ 554
Change in unrealized gains or losses in respect of the Company's share in derivative instruments of unconsolidated investment, tax	0	0	0
Amortization of unrealized gains, tax	$ 57	$ 73	$ 87
Cash dividend declared, per share (in dollars per share)	$ 0.52	$ 0.26	$ 0.21

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net income	$ 101,516	$ 123,349	$ 55,015
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	105,977	107,206	100,798
Amortization of premium from senior unsecured bonds	(513)	(306)	(308)
Accretion of asset retirement obligation	1,778	1,198	829
Stock-based compensation	5,157	3,955	5,571
Amortization of deferred lease income	(2,685)	(2,685)	(2,685)
Income attributable to sale of tax benefits, net of interest expense	(6,962)	(17,467)	(13,823)
Equity in losses of investees	7,735	5,508	3,213
Mark-to-market of derivative instruments	319	4,129	(6,960)
Write-off of unsuccessful exploration activities	3,017	1,579	15,439
Gain on severance pay fund asset	(304)	(119)	1,492
Gain on sale of a subsidiary			(7,628)
Deferred income tax provision	18,473	(39,530)	13,135
Liability for unrecognized tax benefits	(4,647)	2,874	2,561
Deferred lease revenues	(853)	224	(251)
Other		484	(181)
Changes in operating assets and liabilities, net of amounts acquired:
Receivables	(33,280)	(3,806)	47,114
Costs and estimated earnings in excess of billings on uncompleted contracts	(27,078)	2,673	(6,576)
Inventories	6,297	(1,144)	5,359
Prepaid expenses and other	(12,540)	(2,579)	(1,337)
Deposits and other	(1,009)	(648)	584
Accounts payable and accrued expenses	(1,375)	(339)	(9,638)
Due from/to related entities, net		451	(9)
Billings in excess of costs and estimated earnings on uncompleted contracts	2,262	(9,168)	(16,821)
Liabilities for severance pay	(786)	(1,076)	(3,442)
Other long-term liabilities	3,310	(2,561)	(903)
Due from/to Parent		(513)	(955)
Net cash provided by operating activities	159,285	190,025	213,235
Cash flows from investing activities:
Cash acquired in organizational restructuring and share exchange with parent		15,391
Net change in restricted cash, cash equivalents and marketable securities	15,241	43,745	(42,183)
Cash received from sale of a subsidiary			35,250
Capital expenditures	(151,930)	(152,450)	(151,153)
Cash grant received from the U.S. Treasury under Section 1603 of the ARRA			27,427
Investment in unconsolidated companies	(3,569)		(631)
Cash paid for acquisition of controlling interest in a subsidiary, net of cash acquired	(20,135)
Intangible assets acquired		(500)
Decrease in severance pay fund asset, net of payments made to retired employees	1,862	2,843	2,128
Net cash used in investing activities	(158,531)	(90,971)	(129,162)
Cash flows from financing activities:
Proceeds from sale of membership interests to noncontrolling interest, net of transaction costs	44,102	156,635
Proceeds from long-term loans, net of transaction costs	142,500	42,000	140,000
Proceeds from exercise of options by employees	7,249	6,085	981
Proceeds from issuance of senior unsecured notes, net of transaction costs	203,483
Purchase of Senior unsecured notes	(249,468)
Cash received from noncontrolling interest	1,972	1,654	2,234
Purchase of OFC Senior Secured Notes	(6,815)	(30,638)	(12,860)
Proceeds from revolving credit lines with banks	309,400	598,800	2,830,683
Repayment of revolving credit lines with banks	(309,400)	(619,100)	(2,922,400)
Cash received from noncontrolling interest	1,972	1,654	2,234
Payment for acquisition of noncontrolling interest in Crump			(1,490)
Repayments of long-term debt	(62,052)	(71,701)	(111,180)
Cash paid to noncontrolling interest	(64,065)	(19,068)	(11,320)
Cash paid for interest rate cap			(1,505)
Payments of capital leases	(1,178)
Deferred debt issuance costs	(6,402)	(5,316)	(4,785)
Cash dividends paid	(25,682)	(12,716)	(9,555)
Net cash provided by (used in) financing activities	43,541	46,635	(101,197)
Net change in cash and cash equivalents	44,295	145,689	(17,124)
Cash and cash equivalents at beginning of period	185,919	40,230	57,354
Cash and cash equivalents at end of period	230,214	185,919	40,230
Cash paid during the year for:
Interest, net of interest capitalized	55,366	55,492	62,376
Income taxes, net	18,490	10,419	5,787
Supplemental non-cash investing and financing activities:
Increase (decrease) in accounts payable related to purchases of property, plant and equipment	(2,219)	3,810	3,853
Accrued liabilities related to financing activities	6,291	1,665	658
Increase (decrease) in asset retirement cost and asset retirement obligation	714	516	(366)
Opal Transaction [Member]
Cash flows from financing activities:
Cash received from noncontrolling interest	59,897
Cash received from noncontrolling interest	$ 59,897

XML

Note 1 - Business and Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

NOTE

1

— BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Business

Ormat Technologies, Inc. (the “Company”) is primarily engaged in the geothermal and recovered energy business, including the supply of equipment that is manufactured by the Company and the design and construction of power plants for projects owned by the Company or for

third

parties. The Company owns and operates geothermal and recovered energy-based power plants in various countries, including the United States of America (“U.S.”), Kenya, and Guatemala. The Company

’s equipment manufacturing operations are located in Israel.

Most of the Company

’s domestic power plant facilities are Qualifying Facilities under the Public Utility Regulatory Policies Act of

1978

(“PURPA”). The power purchase agreements (“PPAs”) for certain of such facilities are dependent upon their maintaining Qualifying Facility status. Management believes that all of the facilities located in the U.S. were in compliance with Qualifying Facility status requirements as of

December

31,

2016.

Cash dividends

During the years ended

December

31,

2016,

2015,

and

2014,

the Company’s Board of Directors declared, approved, and authorized the payment of cash dividends in the aggregate amount of

$25.7

million

($0.52

per share),

$12.7

million

($0.26

per share), and

$9.6

million

($0.21

per share), respectively. Such dividends were paid in the years declared.

Rounding

Dollar amounts, except per share data, in the notes to these financial statements are rounded to the closest

$1,000,

unless otherwise indicated

.

Basis of presentation

The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and include the accounts of the Company and of all majority-owned subsidiaries in which the Company exercises control over operating and financial policies, and variable interest entities in which the Company has an interest and is the primary beneficiary. Intercompany accounts and transactions have been eliminated in consolidation

.

Investments in less-than-majority-owned entities or other entities in which the Company exercises significant influence over operating and financial policies are accounted for using the equity method of accounting or consolidated if they are a variable interest entity in which the Company has an interest and is the primary beneficiary. Under the equity method, original investments are recorded at cost and adjusted by the Company

’s share of undistributed earnings or losses of such companies. The Company’s earnings or losses in investments accounted for under the equity method have been reflected as “equity in income (losses) of investees, net” on the Company’s consolidated statements of operations and comprehensive income (loss).

Cash and cash equivalents

The Company considers all highly liquid instruments, with an original maturity of

three

months or less, to be cash equivalents

.

Restricted cash, cash equivalents

, and marketable securities

Under the terms of certain long-term debt agreements, the Company is required to maintain certain debt service reserves, cash collateral and operating fund accounts that have been classified as restricted cash and cash equivalents. Funds that will be used to satisfy obligations due during the next

twelve

months are classified as current restricted cash and cash equivalents, with the remainder classified as non-current restricted cash and cash equivalents. Such amounts were invested primarily in money market accounts and commercial paper with a minimum investment grade of “AA”.

Concentration of credit risk

Financial instruments which potentially subject the Company to concentration of credit risk consist principally of temporary cash investments and accounts receivable

.

The Company places its temporary cash investments with high credit quality financial institutions located in the U.S. and in foreign countries. At

December

31,

2016

and

2015,

the Company had deposits totaling

$72.5

million and

$19.0

million, respectively, in

seven

U.S. financial institutions that were federally insured up to

$250,000

per account. At

December

31,

2016

and

2015,

the Company

’s deposits in foreign countries of approximately

$166.2

million and

$181.0

million, respectively, were not insured.

At

December

31,

2016

and

2015,

accounts receivable related to operations in foreign countries amounted to

approximately

$53.3

million and

$27.8

million, respectively. At

December

31,

2016,

and

2015,

accounts receivable from the Company’s major customers (see Note

20)

amounted to approximately

60%

and

66%,

respectively, of the Company’s accounts receivable.

The Company has historically been able to collect on substantially all of its receivable balances, and accordingly,

no

provision for doubtful accounts has been made.

Inventories

Inventories consist primarily of raw material parts and sub-assemblies for power units, and are stated at the lower of cost or market value, using the weighted-average cost method. Inventories are reduced by a provision for slow-moving and obsolete inventories. This provision was not material at

December

31,

2016

and

2015.

Deposits and other

Deposits and other consist primarily of performance bonds for construction projects, long-term insurance contract and receivables, and derivative instruments.

Deferred charges

Deferred charges represent prepaid income taxes on intercompany sales. Such amounts are amortized using the straight-line method and included in income tax provision over the life of the related property, plant and equipment.

Property, plant and equipment, net

Property, plant and equipment are stated at cost. All costs associated with the acquisition, development and construction of power plants operated by the Company are capitalized. Major improvements are capitalized and repairs and maintenance (including major maintenance) costs are expensed. Power plants operated by the Company, which include geothermal wells and exploration and resource development costs, are depreciated using the straight-line method over their estimated useful lives, which range from

15

to

30

years. The other assets are depreciated using the straight-line method over the following estimated useful lives of the assets:

Buildings (in years)		25
Leasehold improvements (in years)	15	-	20
Machinery and equipment — manufacturing and drilling (in years)		10
Machinery and equipment — computers (in years)	3	-	5
Office equipment — furniture and fixtures (in years)	5	-	15
Office equipment — other (in years)	5	-	10
Automobiles (in years)	5	-	7

The cost and accumulated depreciation of items sold or retired are removed from the accounts. Any resulting gain or loss recognized currently and is recorded in the accompanying statements of operations.

The Company capitalizes interest costs as part of constructing power plant facilities. Such capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset

’s estimated useful life. Capitalized interest costs amounted to

$3.3

million,

$4.1

million, and

$3.2

million for the years ended

December

31,

2016,

2015,

and

2014,

respectively.

Cash Grants

From

2009

to

2014,

the Company was awarded cash grants from the U.S. Department of the Treasury (“U.S. Treasury”) for Specified Energy Property in Lieu of Tax Credits under Section

1603

of the American Recovery and Reinvestment Act of

2009

(“ARRA”). The Company recorded the cash grant as a reduction in the carrying value of the related plant and amortized the grants as a reduction in depreciation expense over the plant’s estimated useful life.

Exploration and development costs

The Company capitalizes costs incurred in connection with the exploration and development of geothermal resources once it acquires land rights to the potential geothermal resource. Prior to acquiring land rights, the Company makes an initial assessment that an economically feasible geothermal reservoir is probable on that land. The Company determines the economic feasibility of potential geothermal resources internally, with all available data and external assessments vetted through the exploration department and occasionally using outside service providers. Costs associated with the initial assessment are expensed and included in cost of electricity revenues in the consolidated statements of operations and comprehensive income (loss). Such costs were immaterial during the years ended

December

31,

2016,

2015,

and

2014.

It normally takes

two

to

three

years from the time active exploration of a particular geothermal resource begins to the time a production well is in operation, assuming the resource is commercially viable. However, in certain sites the process

may

take longer due to permitting delays, transmission constrains or any other commercial milestones that are required to be reached in order to pursue the development process.

In most cases, the Company obtains the right to conduct the geothermal development and operations on land owned by the Bureau of Land Management (“BLM”), various states or with private parties. In consideration for certain of these leases, the Company

may

pay an up-front bonus payment which is a component of the competitive lease process. The up-front bonus payments and other related costs, such as legal fees, are capitalized and included in construction-in-process. The annual land lease payments made during the exploration, development and construction phase are expensed as incurred and included in “electricity cost of revenues” in the consolidated statements of operations and comprehensive income (loss). Upon commencement of power generation on the leased land, the Company begins to pay to the lessors long-term royalty payments based on the utilization of the geothermal resources as defined in the respective agreements. Such payments are expensed when the related revenues are earned and included in “electricity cost of revenues” in the consolidated statements of operations and comprehensive income (loss).

Following the acquisition of land rights to the potential geothermal resource, the Company conducts further studies and surveys, including water and soil analyses among others, and augments its database with the results of these studies. The Company then initiates a suite of geophysical surveys to assess the resource and determine drilling locations. If the results of these activities support the initial assessment of the feasibility of the geothermal resource, the Company then proceeds to exploratory drilling and other related activities which

may

include drilling of temperature gradient holes, drilling of slim holes, building access roads to drilling locations, drilling full size production and/or injection wells and flow tests. If the slim hole supports a conclusion that the geothermal resource will support a commercially viable power plant, it

may

be converted to a full-size commercial well, used either for extraction or re-injection or geothermal fluids, or be used as an observation well to monitor and define the geothermal resource. Costs associated with these activities and other directly attributable costs, including interest once physical exploration activities begin and permitting costs are capitalized and included in “construction-in-process”. If the Company concludes that a geothermal resource will not support commercial operations, capitalized costs are expensed in the period such determination is made.

When deciding whether to continue holding lease rights and/or to pursue exploration activity, we diligently prioritize our prospective investments, taking into account resource and probability assessments in order to make informed decisions about whether a particular project will support commercial operations

. As a result, write-off of unsuccessful activities for the year ended

December

31,

2016,

2015

and

2014,

was

$3.0

million,

$1.6

million, and

$15.4

million. In

2016

and

2015,

the write-offs included the exploration costs related to the Company’s exploration activities primarily in the Twilight site in Oregon and the Maui site in Hawaii of

$1.0

million, respectively. In

2014,

the write-offs included the exploration costs related to the Company’s exploration activities in the Wister site in California of

$8.1

million and the Mount Spur site in Alaska of

$7.3

million.

Grants received from the U.S. Department of Energy (“DOE”) are offset against the related exploration and development costs. Such grants amounted to

$0.3

million,

$0.8

million, and

$1.7

million for the years ended

December

31,

2016,

2015,

and

2014,

respectively.

All exploration and development costs that are being capitalized, including the up-front bonus payments made to secure land leases, will be depreciated over their estimated useful lives when the related geothermal power plant is substantially complete and ready for use. A geothermal power plant is substantially complete and ready for use when electricity generation commences.

Asset retirement obligation

The Company records the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. The Company

’s legal liabilities include plugging wells and post-closure costs of power producing sites. When a new liability for asset retirement obligations is recorded, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. At retirement, the obligation is settled for its recorded amount at a gain or loss.

Deferred financing and lease transaction costs

Deferred financing costs are amortized over the term of the related obligation using the effective interest method. Amortization of deferred financing costs is presented as interest expense in the consolidated statements of operations and comprehensive income (loss). Accumulated amortization related to deferred financing costs amounted to

$31.1

million and

$37.2

million at

December

31,

2016

and

2015,

respectively. Amortization expense for the years ended

December

31,

2016,

2015,

and

2014

amounted to

$6.9

million,

$8.8

million, and

$6.5

million, respectively. During the years ended

December

31,

2016,

2015

and

2014

amounts of

$0.1

million,

$0.5

million and

$0.7

million, respectively, were written-off as a result of the extinguishment of liability.

Deferred transaction costs relating to the Puna operating lease (see Note

13)

in the amount of

$4.2

million are amortized using the straight-line method over the

23

-year term of the lease. Amortization of deferred transaction costs is presented in cost of revenues in the consolidated statements of operations and comprehensive income (loss). Accumulated amortization related to deferred lease costs amounted to

$2.1

million and

$2.0

million at

December

31,

2016

and

2015,

respectively. Amortization expense for each of the years ended

December

31,

2016,

2015,

and

2014

amounted to

$0.2

million.

Goodwill

Goodwill represents the excess of the fair value of consideration transferred in the Guadeloupe business combination transaction over the fair value of tangible and intangible assets acquired net of the fair value of liabilities assumed and the fair value of any noncontrolling interest in the acquisition. Goodwill is not amortized but rather subject to periodic impairment testing on an annual basis or if an event occurs or circumstances change that would more likely than not reduce the fair value of reporting unit below its carrying amount.

Intangible assets

Intangible assets consist of allocated acquisition costs of PPAs, which are amortized using the straight-line method over the

13

to

25

-year terms of the agreements (see Note

10

).

Impairment of long-lived assets and long-lived assets to be disposed of

The Company evaluates long-lived assets, such as property, plant and equipment and construction-in-process for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset

may

not be recoverable. Factors which could trigger an impairment include, among others, significant underperformance relative to historical or projected future operating results, significant changes in the Company

’s use of assets or its overall business strategy, negative industry or economic trends, a determination that an exploration project will not support commercial operations, a determination that a suspended project is not likely to be completed, a significant increase in costs necessary to complete a project, legal factors relating to its business or when it concludes that it is more likely than not that an asset will be disposed of or sold.

The Company tests its operating plants that are operated together as a complex for impairment at the complex level because the cash flows of such plants result from significant shared operating activities. For example, the operating power plants in a complex are managed under a combined operation management generally with

one

central control room that controls all of the power plants in a complex and

one

maintenance group that services all of the power plants in a complex. As a result, the cash flows from individual plants within a complex are not largely independent of the cash flows of other plants within the complex. The Company tests for impairment its operating plants which are not operated as a complex as well as its projects under exploration, development or construction that are not part of an existing complex at the plant or project level. To the extent an operating plant becomes part of a complex, the Company will test for impairment at the complex level.

Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated future net undiscounted cash flows expected to be generated by the asset. The significant assumptions that the Company uses in estimating its undiscounted future cash flows include: (i) projected generating capacity of the complex or power plant and rates to be received under the respective PPA(s)

and expected market rates thereafter

and (ii) projected operating expenses of the relevant complex or power plant. Estimates of future cash flows used to test recoverability of a long-lived asset under development also include cash flows associated with all future expenditures necessary to develop the asset.

If the assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. Management believes that no impairment exists for long-lived assets; however, estimates as to the recoverability of such assets

may

change based on revised circumstances. If actual cash flows differ significantly from the Company

’s current estimates, a material impairment charge

may

be required in the future.

Derivative instruments

Derivative instruments (including certain derivative instruments embedded in other contracts) are measured at their fair value and recorded as either assets or liabilities unless exempted from derivative treatment as a normal purchase and sale. All changes in the fair value of derivatives are recognized in earnings unless specific hedge criteria are met, which requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

The Company maintains a risk management strategy that incorporates the use of swap contracts and put options on oil and natural gas prices, forward exchange contracts, interest rate swaps, and interest rate caps to minimize significant fluctuation in cash flows and/or earnings that are caused by oil and natural gas prices, exchange rate or interest rate volatility. Gains or losses on contracts that initially qualify for cash flow hedge accounting, net of related taxes, are included as a component of other comprehensive income or loss and accumulated other comprehensive income or loss are subsequently reclassified into earnings when the hedged forecasted transaction affects earnings. Gains or losses on contracts that are not designated as a cash flow hedge are included currently in earnings.

Foreign currency translation

The U.S. dollar is the functional currency for all of the Company

’s consolidated operations and those of its equity affiliates except for the Guadeloupe power plant. For those entities, all gains and losses from currency translations are included within the line item “Derivatives and foreign currency transaction gains (losses)” within the consolidated statements of operations and comprehensive income (loss). The Euro is the functional currency of the Guadeloupe power plant and thus gains and losses from currency translation adjustments related to Guadeloupe are included as currency translation adjustments in accumulated other comprehensive income in the consolidated statements of equity and in comprehensive income.

Comprehensive income (loss) reporting

Comprehensive income (loss) includes net income or loss plus other comprehensive income (loss), which for the Company consists of changes in unrealized gains or losses in respect of the Company

’s share in derivatives instruments of unconsolidated investment, foreign currency translation adjustments and the mark-to-market gains or losses on derivative instruments designated as a cash flow hedge. For the years ended

December

31,

2016,

2015

and

2014,

the Company reclassified

$9

thousand,

$27

thousand and

$141

thousand, respectively, from other comprehensive income, of which

$12.0

thousand,

$44

thousand and

$228

thousand, respectively, were recorded to reduce interest expense and

$3.0

thousand,

$17

thousand and

$87

thousand, respectively, were recorded against the income tax provision, in the consolidated statements of operations and comprehensive income (loss).

Revenues and cost of revenues

Revenues are primarily related to: (i) sale of electricity from geothermal and recovered energy-based power plants owned and operated by the Company and (ii) geothermal and recovered energy-based power plant equipment engineering, sale, construction and installation, and operating services.

Revenues related to the sale of electricity from geothermal and recovered energy-based power plants and capacity payments are recorded based upon output delivered and capacity provided at rates specified under relevant contract terms. For PPAs agreed to, modified, or acquired in business combinations on or after

July

1,

2003,

the Company determines whether such PPAs contain a lease element requiring lease accounting. Revenue from such PPAs are accounted for in electricity revenues. The lease element of the PPAs is also assessed in accordance with the revenue arrangements with multiple deliverables guidance, which requires that revenues be allocated to the separate earnings processes based on their relative fair value. PPAs with minimum lease rentals which vary over time are generally recognized on the straight-line basis over the term of the PPAs. PPAs with contingent rentals are recognized when earned.

Revenues from engineering, operating services, and parts and product sales are recorded upon providing the service or delivery of the products and parts and when collectability is reasonably assured. Revenues from the supply and/or construction of geothermal and recovered energy-based power plant equipment and other equipment to

third

parties are recognized using the percentage-of-completion method. Revenue is recognized based on the percentage relationship that incurred costs bear to total estimated costs. Costs include direct material, labor, and indirect costs. Selling, marketing, general, and administrative costs are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in job performance, job conditions, and estimated profitability, including those arising from contract penalty provisions and final contract settlements,

may

result in revisions to costs and revenues and are recognized in the period in which the revisions are determined

.

In specific instances where there is a lack of dependable estimates or inherent risks cause forecast to be doubtful, then the completed-contract method is followed. Revenue is recognized when the contract is substantially complete and when collectability is reasonably assured. Costs that are closely associated with the project are deferred as contract costs and recognized similarly to the associated revenues.

Warranty on products sold

The Company generally provides a

one

-year warranty against defects in workmanship and materials related to the sale of products for electricity generation. Estimated future warranty obligations are included in operating expenses in the period in which the related revenue is recognized. Such charges are immaterial for the years ended

December

31,

2016,

2015,

and

2014

.

Research and development

Research and development costs incurred by the Company for the development of existing and new geothermal, recovered energy and remote power technologies are expensed as incurred. Grants received from the DOE are offset against the related research and development expenses. Such grants amounted to

$0

million,

$0

million, and

$0.6

million for the years ended

December

31,

2016,

2015,

and

2014,

respectively

.

Stock-based compensation

The Company accounts for stock-based compensation using the fair value method whereby compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the requisite employee service period (generally the vesting period of the grant). Prior to

2016,

the Company used the Black-Scholes formula to estimate the fair value of the stock-based compensation. In

2016,

the Company used the Exercise Multiple-Based Lattice SAR-Pricing Model to value the stock-based compensation awards to reflect accumulated historic data retained of behavioral parameters.

Tax monetization Transactions

The Company has

three

tax monetization transactions, OPC, ORTP and Opal, as described in Note

14.

  The purpose of these transactions is to form tax partnerships, whereby investors provide cash in exchange for equity interests that provide the holder a right to the majority of tax benefits associated with a renewable energy project.  We account for a portion of the proceeds from the transaction as debt under ASC

470.

  Given that a portion of these transactions is structured as a purchase of an equity interest we also classify a portion as noncontrolling interest consistent with guidance in ASC

810.

  The portion recorded to noncontrolling interest is initially measured as the fair value of the discounted Tax Attributes and cash distributions which represents the partner's residual economic interest.  The residual proceeds is recognized as the initial carrying value of the debt which is classified as a liability associated with sale tax benefits. We apply the effective interest rate method to the liability component as described by ASC

835

and CON

7.

  The tax benefits and cash distributions realized by the partner each period are treated as the debt servicing amounts, giving rise to income attributable to the sale of tax benefits.  The deferred transaction costs have been capitalized and amortized using the effective interest method.

Income taxes

Income taxes are accounted for using the asset and liability approach, which requires the recognition of taxes payable or refundable for the current year and deferred tax assets and liabilities for the future tax consequences of events that have been recognized in the Company

’s financial statements or tax returns. The measurement of current and deferred tax assets and liabilities are based on provisions of the enacted tax law. The effects of future changes in tax laws or rates are not anticipated. The Company accounts for investment tax credits and production tax credits as a reduction to income taxes in the year in which the credit arises. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that, based on available evidence, are not, more likely than not expected to be realized. A full valuation allowance has been established to offset the Company’s U.S. deferred tax assets. Tax benefits from uncertain tax positions are recognized only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. Interest and penalties assessed by taxing authorities on an underpayment of income taxes are included as a component of income tax provision in the consolidated statements of operations and comprehensive income.

Earnings (loss) per share

Basic earnings (loss) per share attributable to the Company

’s stockholders (“earnings (loss) per share”) is computed by dividing net income or loss attributable to the Company’s stockholders by the weighted average number of shares of common stock outstanding for the period. The Company does not have any equity instruments that are dilutive, except for stock-based awards.

The table below shows the reconciliation of the number of shares used in the computation of basic and diluted earnings per share

:

	Year Ended December 31,
	2016		2015		2014
	(In thousands)
Weighted average number of shares used in computation of basic earnings per share		49,469		48,562		45,508
Add:
Additional shares from the assumed exercise of employee stock options		671		625		351
Weighted average number of shares used in computation of diluted earnings per share		50,140		49,187		45,859

The number of stock-based awards that could potentially dilute future earnings per share and were not included in the computation of diluted earnings per share because to do so would have been anti-dilutive was

102,793,

467,766,

and

3,237,593,

respectively, for the years ended

December

31,

2016,

2015,

and

2014.

Use of estimates in preparation of financial statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of such financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. The most significant estimates with regard to the Company

’s consolidated financial statements relate to the useful lives of property, plant and equipment, impairment of long-lived assets and assets to be disposed of, revenue recognition of product sales using the percentage of completion method, asset retirement obligations, and the provision for income taxes.

New Accounting Pronouncements

New accounting pronouncements effective in the year ended

December

31,

2016

Amendments to Fair Value Measurement

In

June

2015,

the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”)

2015

-

10,

Amendment to Fair Value Measurement, Subtopic

820

-

10.

The amendment provides that the reporting entity shall disclose for each class of assets and liabilities measured at fair value in the statement of financial position the following information: for recurring fair value measurements, the fair value measurement at the end of the reporting period, and for non-recurring fair value measurement, the fair value measurement at the relevant measurement date and the reason for the measurement. The amendments in this update are effective for annual reporting periods beginning after

December

15,

2015,

including interim periods within those reporting periods. The adoption of this guidance did not have a material impact on the Company

’s consolidated financial statements.

Amendments to the Consolidation Analysis

In

February

2015,

the FASB issued ASU

2015

-

02,

Amendments to the Consolidation Analysis, Topic

810.

The update provides that all reporting entities that hold a variable interest in other legal entities will need to re-evaluate their consolidation conclusions and potentially revise their disclosures. This amendment affects both variable interest entity (“VIE”) and voting interest entity (“VOE”) consolidation models. The update does not change the general order in which the consolidation models are applied. A reporting entity that holds an economic interest in, or is otherwise involved with, another legal entity (i.e. has a variable interest) should

first

determine if the VIE model applies, and if so, whether it holds a controlling financial interest under that model. If the entity being evaluated for consolidation is not a VIE, then the VOE model should be applied to determine whether the entity should be consolidated by the reporting entity. Since consolidation is only assessed for legal entities, the determination of whether there is a legal entity is important. It is often clear when the entity is incorporated, but unincorporated structures can also be legal entities and judgment

may

be required to make that determination. The update contains a new example that highlights the discretion used to make this legal entity determination. The update is effective for annual reporting periods beginning after

December

15,

2015,

including interim periods within those reporting periods. The adoption of this guidance did not have a material impact on the Company

’s consolidated financial statements.

Simplifying the Presentation of Debt Costs

In

April

2015,

the FASB issued ASU

2015

-

03,

Interest-Imputation of Interest: Simplifying the Presentation of Debt Costs, Subtopic

835

-

30.

The update provides that debt issuance costs related to a recognized debt liability be presented in the balance sheet as direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The amendments in this update are effective for financial statements issued for fiscal years beginning after

December

15,

2015,

and interim periods within those fiscal years. The Company retrospectively adopted this update in its interim period beginning

January

1,

2016.

The impact of the adoption resulted in a reclassification of debt issuance costs totaling $

17.7

million and

$19.1

million as of

December

31,

2016

and

December

31,

2015,

respectively.

In

August

2015,

the FASB issued ASU

2015

-

15,

Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements, Subtopic

835

-

30.

The update clarifies that given the absence of authoritative guidance within Update

2015

-

03

for debt issuance costs described below, debt issuance costs related to line-of-credit arrangements can be deferred and presented as assets and subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings under the line-of-credit arrangement. The amendments in this update are effective for financial statements issued for fiscal years beginning after

December

15,

2015,

and interim periods within those fiscal years. The Company adopted this update in its interim period beginning

January

1,

2016

and continues to present debt issuance costs related to such line-of-credit arrangements as assets amortized ratably over the respective term of the line-of credit arrangements. Debt issuance costs related to such line-of-credit arrangements as of

December

31,

2016

and

December

31,

2015,

totaled

$1.1

million and

$1.0

million, respectively.

New accounting pronouncements effective in future periods

Business Combinations

In

January

2017,

the FASB issued ASU

2017

-

01,

Business Combinations (Topic

805).

The update clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this update primarily provide a screen to determine when a set of assets and activities is not a business and by that reduces the number of transactions that need to be further evaluated. The amendments in this update should be applied prospectively and are effective for financial statements issued for fiscal years beginning after

December

15,

2017,

and interim periods within those fiscal years. Early adoption is permitted. 

The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Statement of Cash Flows

In

November

2016,

the FASB issued ASU

2016

-

018,

Statement of Cash Flows (Topic

230)

– Restricted Cash. The amendments in this update require that a statement of cash flows explain the changes during the period in total cash, cash equivalents, and the amounts generally described as restricted cash or cash equivalents. Therefore, amounts of restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendments in this update should be applied retrospectively for each period presented and are effective for financial statements issued for fiscal years beginning after

December

15,

2017,

and interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Intra-Entity Transfers of Assets Other than Inventory

 

     In

October

2016,

the FASB issued ASU

2016

-

16,

Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory. The amendments in this update require that the entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The new guidance does not apply to intra-entity transfers on inventory. The amendments in this update should be applied for each period presented and are effective for financial statements issued for fiscal years beginning after

December

15,

2017,

and interim periods within those fiscal years. The modified retrospective approach will be required for transition to the new guidance, with cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. Early adoption is permitted in the

first

quarter of

2017.

The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Interests Held through Related Parties that are under Common Control

 

     In

October

2016,

the FASB issued ASU

2016

-

17,

Consolidation (Topic

810):

Interests held through Related Parties that are under Common Control. The amendments in this update require that if a decision maker is required to evaluate whether it is the primary beneficiary of a VIE, it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The amendments in this update should be applied retrospectively for each period presented and are effective for financial statements issued for fiscal years beginning after

December

15,

2016,

and interim periods within those fiscal years. The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Improvement to Employee Share-Based Payment Accounting

In

March

2016,

the FASB issued ASU

2016

-

09,

Improvement to Employee Share-Based Payment Accounting, an

 update to the guidance on stock-based compensation. Under the new guidance, all excess tax benefits and tax deficiencies will be recognized in the income statement as they occur. This will replace the current guidance, which requires tax benefits that exceed compensation cost (windfalls) to be recognized in equity. It will also eliminate the need to maintain a “windfall pool,” and will remove the requirement to delay recognizing a windfall until it reduces current taxes payable. The new guidance will also change the cash flow presentation of excess tax benefits, classifying them as operating inflows, consistent with other cash flows related to income taxes. Today, windfalls are classified as financing activities. Also, this will affect the dilutive effects in earnings per share, as there will no longer be excess tax benefits recognized in additional paid in capital. Today those excess tax benefits are included in assumed proceeds from applying the treasury stock method when computing diluted EPS. Under the amended guidance, companies will be able to make an accounting policy election to either

(1)

continue to estimate forfeitures or

(2)

account for forfeitures as they occur. This updated guidance is effective for annual and interim periods beginning after 

December

15,

2016.

 Early adoption is permitted. The Company is currently evaluating the potential impact, if any, of the adoption of this update on its consolidated financial statements, however, any impact is not expected to be material.

Leases

In

February

2016,

the FASB issued ASU

2016

-

02,

Leases, Topic

842.

The amendment in this Update introduce a number of changes and simplifications from previous guidance, primarily the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The Update retains the distinction between finance leases and operating leases and the classification criteria between the

two

types remain substantially similar. Also, lessor accounting remains largely unchanged from previous guidance, however, key aspects in the Update were aligned with the revenue recognition guidance in Topic

606.

Additionally, the Update defines a lease as a contract, or part of a contract, that conveys the right to control the use of identified asset for a period of time in exchange for considerations. Control over the use of the identified means that the customer has both (a) the right to obtain substantially all of the economic benefits from the use of the asset and (b) the right to direct the use of the asset. The amendments in this update are effective for annual reporting periods beginning after

December

15,

2018,

including interim periods within those reporting periods. Early adoption is permitted. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements.

Recognition and Measurement of Financial Assets and Financial Liabilities

In

January

2016,

the FASB issued ASU

2016

-

01,

Recognition and Measurement of Financial Assets and Financial Liabilities. The update primarily requires that an entity should present separately, in other comprehensive income, the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk if the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. The application of this update should be by means of cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The amendments in this update are effective for financial statements issued for fiscal years beginning after

December

15,

2017,

and interim periods within those fiscal years. Early adoption is permitted as of the beginning of the fiscal year of adoption. The Company is currently evaluating the potential impact, if any, of the adoption of this update on its consolidated financial statements.

Simplifying the Measurement of Inventory

In

July

2015,

the FASB issued ASU

2015

-

11,

Simplifying the Measurement of Inventory, Topic

330.

The update contains no amendments to disclosure requirements, but replaces the concept of

‘lower of cost or market’ with that of ‘lower of cost and net realizable value’. The amendments in this update are effective for annual reporting periods beginning after

December

15,

2016,

including interim periods within those reporting periods. The amendments should be applied prospectively with early adoption permitted. The Company estimates that the potential impact, if any, of the adoption of this update on its consolidated financial statements is immaterial.

Revenues from Contracts with Customers

In

May

2014,

the FASB issued ASU

2014

-

09,

Revenues from Contracts with Customers, Topic

606,

which was a joint project of the FASB and the International Accounting Standards Board to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The update provides that an entity should recognize revenue in connection with the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Specifically, an entity is required to apply each of the following steps:

(1)

identify the contract(s) with the customer;

(2)

identify the performance obligations in the contracts;

(3)

determine the transaction price;

(4)

allocate the transaction price to the performance obligation in the contract; and

(5)

recognize revenue when (or as) the entity satisfies a performance obligation. ASU

2014

-

09

also prescribes additional financial presentations and disclosures. The amendments in this update are effective for annual reporting periods beginning after

December

15,

2017,

including interim periods within those reporting periods. Early adoption is permitted no earlier than

2017

for calendar fiscal year entities. The Company expects the adoption of this standard to have an immaterial impact, if any, on its Electricity segment as it accounts for its PPA

’s under ASC

840,

Leases. The Company still evaluates the potential impact of the adoption of the standard on its Product segment, however, it believes that such impact, if any, will be immaterial.

In

March

2016,

the FASB issued ASU

2016

-

08,

Principal versus Agent Considerations. The amendment in this Update do not change the core principal of the guidance and are intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations. When another entity is involved in providing goods or services to a customer, an entity is required to determine if the nature of its promise is to provide the specific good or service itself (that is, the entity is a principal) or to arrange for that good or service to be provided by the other party (that is, the entity is an agent). The guidance includes indicators to assist an entity in determining whether it acts as a principal or agent in a specified transaction. The amendments in this update are effective for annual reporting periods beginning after

December

15,

2017,

including interim periods within those reporting periods. Early adoption is permitted no earlier than

2017

for calendar fiscal year entities. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements,

however, it believes that any such impact, if any, will be immaterial.

XML

Note 2 - Share Exchange Transaction

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Share Exchange Transaction [Text Block]

NOTE

2

— SHARE EXCHANGE TRANSACTION

Share exchange transaction

On

February

12,

2015,

the Company completed the share exchange transaction with its then-parent entity, Ormat Industries Ltd. ("OIL") following which, the Company became a noncontrolled public company and its public float increased from approximately

40%

to approximately

76%

of its total shares outstanding. Under the terms of the share exchange, OIL shareholders received

0.2592

shares in the Company for each share in OIL, or an aggregate of approximately

30.2

million shares, reflecting a net issuance of approximately

3.0

million shares (after deducting the

27.2

million shares that OIL held in the Company). Consequently, the number of total shares of the Company outstanding increased from approximately

45.5

million shares to approximately

48.5

million shares as of the closing of the share exchange.

In exchange, the Company also received

$15.4

million in cash,

$0.6

million in other assets and

$12.1

million in land and buildings and assumed

$0.5

million in liabilities. OIL's principal business purpose was to hold its interest in the Company and the transaction resulted in a transfer of non-material assets from OIL to the Company. Therefore, there was no change in the reporting entity as a result of the transaction and the Company recognized the transfer of net assets at their carrying value as presented in OIL's financial statements. Any activities of OIL will be accounted for prospectively by the Company.

XML

Note 3 - Northleaf Transactions and Business Acquisition

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Sale of Membership Interests [Text Block]

NOTE

3

— NORTHLEAF TRANSACTIONS AND BUSINESS AQUISITION

Northleaf transactions

On

April

30,

2015,

Ormat Nevada Inc. (“Ormat Nevada”), a wholly-owned subsidiary of the Company, closed the sale of approximately

36.75%

of the aggregate membership interests in ORPD LLC (“ORPD”), a new holding company and subsidiary of Ormat Nevada, that indirectly owns the Puna geothermal power plant in Hawaii, the Don A. Campbell geothermal power plant in Nevada, and

nine

power plant units across

three

recovered energy generation assets known as OREG

1,

OREG

2

and OREG

3

to Northleaf Geothermal Holdings, LLC for

$162.3

million. The net proceeds to the Company were

$156.8

million after payment of

$5.5

million of transaction costs. The sale was made under the Agreement for Purchase of Membership Interests dated

February

5,

2015.

This transaction closed on

April

30,

2015

and resulted in a taxable gain in the U.S. of approximately

$102.1

million, for which the Company utilized a portion of its Net Operating Loss (“NOL”) and tax credit carryforwards to fully offset the tax impact of the gain.

Following the transaction, the Company maintains control of ORPD and continues to consolidate the entity with non-controlling interest being recorded. Consequently, the Company recorded the net proceeds from the issuance of membership interests as an increase to additional paid-in capital of

$71.3

million and non- controlling interests of

$85.5

million. See Note

19

for tax details.

On

November

23

,

2016,

Ormat Nevada, closed a follow-on sale of

36.75%

equity interest in the

second

phase of the Don A. Campbell power plant for proceeds of approximately

$44.2

million. The Don A. Campbell commenced operations in

September

2015

and sells its electricity to SCPPA under a

20

year PPA. Following the closing, the power plant was contributed to the existing ORPD, as agreed upon under the ORPD agreement with Northleaf Geothermal Holdings, LLC that was executed on

April

30,

2015.

The net proceeds to the Company were

$44.1

million after payment of

$0.1

million of transaction costs and resulted in a taxable gain in the U.S. of approximately

$21.4

million, for which the Company utilized a portion of its Net Operating Loss (“NOL”) and tax credit carryforwards to fully offset the tax impact of the gain.

Following the transaction, the Company continue to maintain control of ORPD and consolidate the entity with additional noncontrolling interest being recorded. Consequently, the Company recorded the net proceeds from the issuance of membership interests as an increase to additional paid-in capital of

$7.8

million and non- controlling interests of

$36.3

million. See Note

19

for tax details.

Guadeloupe power plant transaction

In

July

2016,

we announced that we closed the previously announced acquisition of Geothermie Bouillante SA (“GB”). GB owns and operates the

14.75

MW Bouillante geothermal power plant located in Guadeloupe Island, a French territory in the Caribbean, which currently generates approximately

13

MW. GB also owns

two

exploration licenses providing an expansion potential of up to

45

MW of capacity.

Pursuant to the terms of an Amended and Restated Investment Agreement (“Investment Agreement”) and Shareholders Agreement with Sageos Holding (“Sageos”), a wholly owned subsidiary of Bureau de Recherches Géologiques et Minières (“BRGM”), the Company together with Caisse des Dépôts et Consignations (“CDC”), a

 French state-owned financial organization, acquired an approximately

80%

interest in GB, allocated

75%

to the Company and

25%

to CDC. The Company and CDC will gradually increase their combined interest in GB to

85%

and Sageos will hold the remaining balance. As part of the agreement, CDC will pay the Company a premium.

Pursuant to the agreements, the Company paid approximately

$20.6

million to Sageos for its approximately

60%

interest in GB. In addition, the Company is committed to further invest

$8.4

million (approximately

€7.5

million) in the next

two

years, which will increase the Company

’s interest to

63.75%.

The cash will be used mainly for the enhancement of the power plant.

The Company has planned modifications to the existing equipment as well as to further develop the asset, with a potential of reaching a total of

45

MW in phased development by

2021.

Under the Investment Agreement, the Company will pay Sageos an additional amount of up to

$13.4

million (approximately

€12

million) subject to the achievement of agreed production thresholds and capacity expansion within a defined time period.

The Bouillante power plant sells its electricity under a

 

15

-year PPA that was entered into in

February

2016

with Électricité de France S.A. (“EDF”), the French electric utility. The Company plans to optimize the use of the resource at the existing facilities and recover its current production to its design capacity of

14.75

MW by mid-

2017.

The Company accounted for the transaction based on the provision of Accounting Standard Codification

805,

Business Combinations, and consequently recorded intangible asset of

$33.0

million pertaining to the

15

-year PPA with EDF and

$7.1

million of goodwill. Additionally, following the transaction, the Company gained control over GB effective

July

5,

2016

and consolidated the entity with redeemable noncontrolling interest of

$5.0

million and noncontrolling interest of

$8.3

million being recorded. The redeemable noncontrolling interest pertains to Sageos right to sell its equity interest in GB to the Company for cash considerations. The noncontrolling interest pertains to CDC and was included under noncontrolling interest in the consolidated statements of equity.

The revenues of GB of approximately

$8.1

million were included in the Company

’s consolidated statements of operations and comprehensive income for year ended

December

31,

2016.

Viridity Transaction

On

December

29,

2016

the Company entered into a definitive agreement to acquire substantially all of the business and assets of Viridity Energy, Inc. (“Viridity”), a privately held Philadelphia-based company engaged in demand response, energy management and storage of energy. The acquisition is expected to close early

2017.

Initial consideration for the acquisition is

$35

million, which will be paid at closing and is subject to adjustment in certain cases. Additional contingent consideration will be payable in

two

installments upon the achievement of certain performance milestones measured at the end of fiscal years

2017

and

2020.

Using proprietary software and solutions, Viridity serves primarily retail energy providers, utilities, and large industrial and commercial clients. Viridity

’s offerings enable its clients to optimize and monetize their energy management, demand response and storage facilities potential by interacting on their behalf with regional transmission organizations and independent system operators. Founded in

2008,

Viridity has under contract over

850

MW across

3,000

sites, including management of a portfolio of non-utility storage assets located in the northeastern US with over

80,000

operational market hours.

XML

Note 4 - Inventories

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Inventory Disclosure [Text Block]

NOTE

4

— INVENTORIES

Inventories consist of the following:

	December 31,
	2016		2015
	(Dollars in thousands)
Raw materials and purchased parts for assembly	$	5,429	$	8,819
Self-manufactured assembly parts and finished products		6,571		9,255
Total	$	12,000	$	18,074

XML

Note 5 - Cost and Estimated Earnings on Uncompleted Contracts

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Long-term Contracts or Programs Disclosure [Text Block]

NOTE

5

— COST AND ESTIMATED EARNINGS ON UNCOMPLETED CONTRACTS

Cost and estimated earnings on uncompleted contracts consist of the following:

	December 31,
	2016			2015
	(Dollars in thousands)
Costs and estimated earnings incurred on uncompleted contracts	$	402,357		$	279,176
Less billings to date		(381,789	)		(287,948	)
Total	$	20,568		$	(8,772	)

These amounts are included in the consolidated balance sheets under the following captions:

	December 31,
	2016			2015
	(Dollars in thousands)
Costs and estimated earnings in excess of billings on uncompleted contracts	$	52,198		$	25,120
Billings in excess of costs and estimated earnings on uncompleted contracts		(31,630	)		(33,892	)
Total	$	20,568		$	(8,772	)

The completion costs of the Company

’s construction contracts are subject to estimation. Due to uncertainties inherent in the estimation process, it is reasonably possible that estimated contract earnings will be further revised in the near term.

XML

Note 6 - Accumulated Loss of Unconsolidated Company in Excess of Investment

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Equity Method Investments and Joint Ventures Disclosure [Text Block]

NOTE

6

—

Accumulated loss of unconsolidated company in excess of investment

Accumulated loss of unconsolidated company in excess of investment

mainly consist of the following:

	December 31,
	2016			2015
	(Dollars in thousands)
Sarulla	$	(11,081	)	$	(8,100	)

The Sarulla Project

The Company holds a

12.75%

equity interest in a consortium which is in the process of developing the Sarulla geothermal power project in Indonesia with an expected generating capacity of approximately

330

megawatts (“MW”). The Sarulla project is located in Tapanuli Utara, North Sumatra, Indonesia and will be owned and operated by the consortium members under the framework of a Joint Operating Contract (“JOC”) and Energy Sales Contract (“ESC”) that were signed on

April

4,

2013.

Under the JOC, PT Pertamina Geothermal Energy (“PGE”), the concession holder for the project, has provided the consortium with the right to use the geothermal field, and under the ESC, PT PLN, the state electric utility, will be the off-taker at Sarulla for a period of

30

years. In addition to its equity holdings in the consortium, the Company designed the Sarulla plant and will supply its Ormat Energy Converters (“OECs”) to the power plant, as further described below.

The project is being constructed in

three

phases of a total

321

MW, utilizing both steam and brine extracted from the geothermal field to increase the power plant

’s efficiency. The

first

phase with

110

MW capacity is currently under testing and expected to commence operation in

March

2017.

For the

second

phase power plant, engineering and procurement has been substantially completed, site construction is in progress and all of the major generating units including those to be supplied by Ormat were delivered. For the

third

phase, engineering, procurement and construction work at the site are in progress and manufacturing of equipment to be supplied by Ormat is underway as planned. Drilling for the

second

and

third

phases is still ongoing and the project has achieved to date, based on preliminary estimates, approximately

80%

of the required production capacity and over

85%

of the required injection capacity. The project has missed a few milestones defined under the loan documents, but has received waivers from the lenders and as of now the project is in compliance with lenders requirements. The project is still experiencing delays in the field development and cost overruns resulting from delays and excess drilling costs. Due to the cost overrun in drilling, the lenders have requested from the sponsors to commit for additional equity. The sponsors have agreed and financing documents were revised to reflect this request. With respect to Ormat’s role as a supplier, all contractual milestones under the supply agreement were achieved.

On

May

16,

2014,

the consortium closed

$1.17

billion in financing for the development of the Sarulla project with a consortium of lenders comprised of Japan Bank for International Cooperation (“JBIC”), the Asian Development Bank and

six

commercial banks and obtained construction and term loans on a limited recourse basis backed by a political risk guarantee from JBIC. Of the

$1.17

billion,

$0.1

billion (which was drawn down by the Sarulla project company on

May

23,

2014)

bears a fixed interest rate and

$1.07

billion bears interest at a rate linked to LIBOR.

The Sarulla consortium entered into interest rate swap agreements with various international banks in order to fix the Libor interest rate on up to

$0.96

billion of the

$1.07

billion credit facility at a rate of

3.4565%.

The interest rate swap became effective as of

June

4,

2014

along with the

second

draw-down by the project company of

$50.0

million.

The Sarulla project company accounted for the interest rate swap as a cash flow hedge upon which changes in the fair value of the hedging instrument, relative to the effective portion, will be recorded in other comprehensive income. As such, during the year ended

December

31,

2016

and

2015,

the project recorded a gain of

$9.3

million and $

8.0

million, respectively, net of deferred tax, of which the Company's share was

$1.2

million and

$1.0

million, respectively, which was recorded in other comprehensive income. The related accumulated loss recorded by the Company in other comprehensive income (loss) as of

December

31,

2016

is

$5.9

million.

Pursuant to a supply agreement that was signed in

October

2013,

the Company is supplying its OECs to the power plant and has added the

$255.6

million supply contract to its Product Segment backlog. The Company started to recognize revenue from the project during the

third

quarter of

2014

and will continue to recognize revenue over the course

of next year. The Company has eliminated the related intercompany profit of

$12.0

million against equity in loss of investees.

During the year ended

December

31,

2016,

the Company made an additional

cash equity investment contribution to the Sarulla project in the amount of

$3.6

million.

XML

Note 7 - Variable Interest Entities

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Disclosure Of Variable Interest Entities [Text Block]

NOTE

7

— VARIABLE INTEREST ENTITIES

The Company

’s overall methodology for evaluating transactions and relationships under the variable interest entity (“VIE”) accounting and disclosure requirements includes the following

two

steps: (i) determining whether the entity meets the criteria to qualify as a VIE; and (ii) determining whether the Company is the primary beneficiary of the VIE.

In performing the

first

step, the significant factors and judgments that the Company considers in making the determination as to whether an entity is a VIE include

:

• The design of the entity, including the nature of its risks and the purpose for which the entity was created, to determine the variability that the entity was designed to create and distribute to its interest holders ;

• The nature of the Company ’s involvement with the entity;

• Whether control of the entity may be achieved through arrangements that do not involve voting equity ;

• Whether there is sufficient equity investment at risk to finance the activities of the entity; and

• Whether parties other than the equity holders have the obligation to absorb expected losses or the right to receive residual returns .

If the Company identifies a VIE based on the above considerations, it then performs the

second

step and evaluates whether it is the primary beneficiary of the VIE by considering the following significant factors and judgments

:

• Whether the Company has the power to direct the activities of the VIE that most significantly impact the entity ’s economic performance; and

• Whether the Company has the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE .

The Company

’s VIEs include certain of its wholly owned subsidiaries that own

one

or more power plants with long-term PPAs. In most cases, the PPAs require the utility to purchase substantially all of the plant’s electrical output over a significant portion of its estimated useful life. Most of the VIEs have associated project financing debt that is non-recourse to the general creditors of the Company, is collateralized by substantially all of the assets of the VIE and those of its wholly owned subsidiaries (also VIEs) and is fully and unconditionally guaranteed by such subsidiaries. The Company has concluded that such entities are VIEs primarily because the entities do not have sufficient equity at risk and/or subordinated financial support is provided through the long-term PPAs. The Company has evaluated each of its VIEs to determine the primary beneficiary by considering the party that has the power to direct the most significant activities of the entity. Such activities include, among others, construction of the power plant, operations and maintenance, dispatch of electricity, financing and strategy. Except for power plants that it acquired, the Company is responsible for the construction of its power plants and generally provides operation and maintenance services. Primarily due to its involvement in these and other activities, the Company has concluded that it directs the most significant activities at each of its VIEs and, therefore, is considered the primary beneficiary. The Company performs an ongoing reassessment of the VIEs to determine the primary beneficiary and

may

be required to deconsolidate certain of its VIEs in the future. The Company has aggregated its consolidated VIEs into the following categories: (i) wholly owned subsidiaries with project debt; and (ii) wholly owned subsidiaries with PPAs.

The tables below detail the assets and liabilities (excluding intercompany balances which are eliminated in consolidation) for the Company

’s VIEs, combined by VIE classifications, that were included in the consolidated balance sheets as of

December

31,

2016

and

2015:

	December 31, 2016
	Project Debt		PPAs
	(Dollars in thousands)
Assets:
Restricted cash and cash equivalents	$	34,262	$	—
Other current assets		157,351		7,482
Property, plant and equipment, net		1,305,254		177,970
Construction-in-process		48,128		72,725
Other long-term assets		24,802		—
Total assets	$	1,569,797	$	258,177
Liabilities:
Accounts payable and accrued expenses	$	10,900	$	3,992
Long-term debt		668,815		—
Other long-term liabilities		126,879		5,779
Total liabilities	$	806,594	$	9,771

	December 31, 2015
	Project Debt		PPAs
	(Dollars in thousands)
Assets:
Restricted cash, cash equivalents and marketable securities	$	49,503	$	—
Other current assets		114,500		4,044
Property, plant and equipment, net		1,310,027		171,231
Construction-in-process		127,825		1,340
Other long-term assets		44,279		(1	)
Total assets	$	1,646,134	$	176,614
Liabilities:
Accounts payable and accrued expenses	$	11,404	$	2,931
Long-term debt		648,028		—
Other long-term liabilities		78,843		5,358
Total liabilities	$	738,275	$	8,289

XML

Note 8 - Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Fair Value Disclosures [Text Block]

NOTE

8

— FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value measurement guidance clarifies that fair value is an exit price, representing the amount that would be received upon selling an asset or paid upon transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level

1

measurements) and the lowest priority to unobservable inputs (Level

3

measurements). The

three

levels of the fair value hierarchy under the fair value measurement guidance are described below

:

Level

1

— Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities;

Level

2

— Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability;

Level

3

— Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (supported by little or no market activity).

The following table sets forth certain fair value information at

December

31,

2016

and

2015

for

financial assets and liabilities measured at fair value by level within the fair value hierarchy, as well as cost or amortized cost. As required by the fair value measurement guidance, assets and liabilities are classified in their entirety based on the lowest level of inputs that is significant to the fair value measurement.

				December 31, 2016
				Fair Value
	Carrying Value at December 31, 2016			Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets:
Current assets:
Cash equivalents (including restricted cash accounts)	$	14,922		$	14,922		$	14,922	$	—		$	—
Derivatives:
Contingent receivable (1)		1,443			1,443			—		—			1,443
Liabilities:
Current liabilities:
Derivatives:
Contingent payables (1)		(11,581	)		(11,581	)		—		—			(11,581	)
Warrants (1)		(3,429	)		(3,429	)							(3,429	)
Currency forward contracts (2)		(481	)		(481	)		—		(481	)		—
	$	874		$	874		$	14,922	$	(481	)	$	(13,567	)

				December 31, 2015
				Fair Value
	Carrying Value at December 31, 2015			Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	31,428		$	31,428		$	31,428	$	—		$	—
Derivatives:
Currency forward contracts (2)		7			7			—		7			—
Liabilities:
Current liabilities:
Derivatives:
Currency forward contracts (2)		(169	)		(169	)		—		(169	)		—
	$	31,266		$	31,266		$	31,428	$	(162	)	$	—

(1)

  

These amounts relate to contingent receivables and payables pertaining to the Guadeloupe power plant purchase transaction, valued primarily based on unobservable inputs and are included within "Prepaid expenses and other" and "Other long-term liabilities" on

December

31,

2016

in the consolidated balance sheets with the corresponding gain or loss being recognized within "Derivatives and foreign currency transaction gains (losses)" in the consolidated statement of operations and comprehensive income.

(2)

These amounts relate to derivatives which represent currency forward contracts valued primarily based on observable inputs, including forward and spot prices for currencies, netted against contracted rates and then multiplied against notional amounts, and are included within “prepaid expenses and other” and “accounts payable and accrued expenses” on

December

31,

2016

and

December

31,

2015,

in the consolidated balance sheet with the corresponding gain or loss being recognized within “Derivatives and foreign currency transaction gains (losses)” in the consolidated statement of operations and comprehensive income.

The amounts set forth in the tables above include investments in debt instruments and money mark

et funds (which are included in cash equivalents). Those securities and deposits are classified within Level

1

of the fair value hierarchy because they are valued using quoted market prices in an active market.

The following table presents the amounts of gain (loss) recognized in the consolidated statements of operations and comprehensive income (loss) on derivative instruments not designated as hedges:

		Amount of recognized gain (loss)
Derivatives not designated as hedging instruments	Location of recognized gain (loss)	2016			2015			2014
		(Dollars in thousands)
Call options on natural gas price	Derivatives and foreign currency transaction gain (losses)	$	(1,340	)	$	—		$	—
Call and put options on oil price	Derivatives and foreign currency transaction gain (losses)		(1,313	)		—			—
Swap transaction on oil price	Electricity revenues		—			—			2,728
Swap transactions on natural gas price	Electricity revenues		—			1,158			2,996
Contingent considerations	Derivatives and foreign currency transaction gain (losses)		(1,527	)		—			—
Currency forward contracts	Derivatives and foreign currency transaction gain (losses)		238			(1,206	)		(4,949	)
		$	(3,942	)	$	(48	)	$	775

On

September

3,

2013,

the Company entered into a Natural Gas Index (“NGI”) swap contract with a bank covering a notional quantity of approximately

4.4

million British Thermal Units (“MMbtu”) for settlement effective

January

1,

2014

until

December

31,

2014,

in order to reduce its exposure to fluctuations in natural gas prices under its Power Purchase Agreements (“PPAs”) with Southern California Edison to below

$4.035

per MMbtu. The contract did not have up-front costs. Under the terms of this contract, the Company made floating rate payments to the bank and received fixed rate payments from the bank on each settlement date. The swap contract had a monthly settlement whereby the difference between the fixed price of

$4.035

per MMbtu and the market price on the

first

commodity business day on which the relevant commodity reference price is published in the relevant calculation period

(January

1,

2014

to

December

1,

2014)

was settled on a cash basis.

On

October

16,

2013,

the Company entered into an NGI swap contract with a bank covering a notional quantity of approximately

4.2

million MMbtu for settlement effective

January

1,

2014

until

December

31,

2014,

in order to reduce its exposure to fluctuations in natural gas prices under its PPAs with Southern California Edison to below

$4.103

per MMbtu. The contract did not have any up-front costs. Under the terms of this contract, the Company made floating rate payments to the bank and received fixed rate payments from the bank on each settlement date. The swap contract had a monthly settlement whereby the difference between the fixed price of

$4.103

per MMbtu and the market price on the

first

commodity business day on which the relevant commodity reference price is published in the relevant calculation period

(January

1,

2014

to

December

1,

2014)

was settled on a cash basis.

On

October

16,

2013,

the Company entered into a New York Harbor Ultra-Low Sulfur Diesel swap contract with a bank covering a notional quantity of

275,000

BBL effective from

January

1,

2014

until

December

31,

2014

to reduce the Company’s exposure to fluctuations in the energy rate caused by fluctuations in oil prices under the

25

MW PPA for the Puna complex. The Company entered into this contract because the swap had a high correlation with the avoided costs (which are incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others) that Hawaii Electric Light Company (“HELCO”) uses to calculate the energy rate. The contract did not have any up-front costs. Under the term of this contract, the Company made floating rate payments to the bank and received fixed rate payments from the bank on each settlement date

($125.15

per BBL). The swap contract had a monthly settlement whereby the difference between the fixed price of

$125.15

per BBL and the monthly average market price was settled on a cash basis.

On

March

6,

2014,

and on

May

14,

2015,

the Company entered into NGI swap contracts with a bank covering a notional quantity of approximately

2.2

MMbtu for settlement effective

January

1,

2015

until

March

31,

2015,

and covering a notional quantity of approximately

2.4

MMbtu for settlement effective

June

1,

2015

until

December

31,

2015,

respectively, in order to reduce its exposure to fluctuations in natural gas prices under its PPAs with Southern California Edison to below

$4.95

per MMbtu and below

$3.00

per MMbtu, respectively. The contracts did not have any up-front costs. Under the terms of these contracts, the Company made, and will make, floating rate payments to the bank and received, and will receive, fixed rate payments from the bank on each settlement date. The swap contracts have monthly settlements whereby the difference between the fixed price and the market price on the

first

commodity business day on which the relevant commodity reference price is published in the relevant calculation period

(January

1,

2015

to

March

1,

2015

and

June

1,

2015

to

December

31,

2015)

are settled on a cash basis.

On

February

2,

2016,

the Company entered into Henry Hub Natural Gas Future contracts under which it

 has written a number of call options covering a notional quantity of approximately

4.1

MMbtu with exercise prices of

$2

and expiration dates ranging from

February

24,

2016

until

December

27,

2016

in order to reduce its exposure to fluctuations in natural gas prices under its PPAs with Southern California Edison. The Company received an aggregate premium of approximately

$1.9

million from these call options. The call option contracts have monthly expiration dates at which the options can be called and the Company would have to settle its liability on a cash basis.

On

February

24,

2016,

the Company entered into Brent Oil Future contracts under which it has written a number of call options covering a notional quantity of approximately

185,000

barrels (“BBL”) of Brent with exercise prices of

$32.80

to

$35.50

and expiration dates ranging from

March

24,

2016

until

December

22,

2016

in order to reduce its exposure to fluctuations in Brent prices under its PPA with HELCO. The Company received an aggregate premium of approximately

$1.1

million from these call options. The call option contracts have monthly expiration dates whereby the options can be called and the Company would have to settle its liability on a cash basis. Moreover, during

March

2016,

the Company rolled

2

existing call options covering a total notional quantity of

31,800

BBL of Brent in order to limit its exposure to

$41

to

$42.50

instead of

$32.80

to

$33.50.

In addition, the Company entered into short risk reversal transactions (sell call and buy put options) by rolling existing call options covering notional quantities of

16,500

BBL and

17,000

BBL in order to limit its exposure from the outstanding call options originally entered into in

February

2016

to a range of

$28.50

to

$37.50

and

$28

to

$38.50,

respectively.

The foregoing future, forward and swap transactions have not been designated as hedge transactions and are marked to market with the corresponding gains or losses recognized within “Derivatives and foreign currency transaction gains (losses)” and “Electricity revenues” in the consolidated statements of operations and comprehensive income, respectively. The Company recognized a net

 loss from these transactions of

$2.4

million,

$1.2

million and

$4.9

million in the years ended

December

31,

2016,

2015

and

2014,

respectively, under Derivatives and foreign currency transaction gains (losses), and a net gain of

$1.2

million and

$5.7

million, in the years ended

December

31,

2015,

and

2014,

respectively, under Electricity revenues.

There were no transfers of assets or liabilities between Level

 

1,

Level

2

and Level 

3

during the year ended

December

 

31,

2016.

The fair value of the Company

’s long-term debt is as follows:

	Fair Value				Carrying Amount
	2016		2015		2016		2015
	(Dollars in millions)				(Dollars in millions)
Olkaria III Loan - DEG	$	16.3	$	24.2	$	15.8	$	23.7
Olkaria III Loan - OPIC		253.4		262.6		246.6		264.6
Olkaria IV Loan - DEG 2		50.9		—		50.0		—
Amatitlan Loan		37.3		41.7		36.8		40.3
Senior Secured Notes:
Ormat Funding Corp. ("OFC")	17.0			30.0		17.0		30.0
OrCal Geothermal Inc. ("OrCal")		37.4		43.8		35.2		43.3
OFC 2 LLC ("OFC 2")		249.0		231.1		247.2		262.0
Don A. Campbell 1 ("DAC1")		88.9		—		92.4		—
Senior Unsecured Bonds		200.1		264.5		204.3		250.0
Other long-term debt		10.4		6.7		11.2		6.7

The fair value of OFC Senior Secured Notes was determined using observable market prices as these securities are traded. The fair value of all the long-term debt is determined by a valuation model, which is based on a conventional discounted cash flow methodology and utilizes assumptions of current borrowing rates

.

The fair value of revolving lines of credit is determined using a comparison of market-based price sources that are reflective of similar credit ratings to those of the Company.

The carrying value of other financial instruments, such as revolving lines of credit and deposits approximates fair value.

The following table presents the fair value of financial instruments as of

December

 

31,

2016:

	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III - DEG	$	—	$	—	$	16.3	$	16.3
Olkaria III - OPIC		—		—		253.4		253.4
Olkaria IV - DEG 2		—		—		50.9		50.9
Amatitlan loan		—		37.3		—		37.3
Senior Secured Notes:
OFC		—		17.0		—		17.0
OrCal		—		—		37.4		37.4
OFC 2		—		—		249.0		249.0
Don A. Campbell 1 ("DAC1")		—		—		88.9		88.9
Senior unsecured bonds		—		—		200.1		200.1
Other long-term debt		—		3.3		7.1		10.4
Deposits		14.4		—		—		14.4

The following table presents the fair value of financial instruments as of

December

 

31,

2015:

	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III Loan - DEG	$	—	$	—	$	24.2	$	24.2
Olkaria III Loan - OPIC		—		—		262.6		262.6
Amatitlan Loan		—		41.7		—		41.7
Senior Secured Notes:
OFC		—		30.0		—		30.0
OrCal		—		—		43.8		43.8
OFC 2		—		—		231.1		231.1
Senior unsecured bonds		—		—		264.5		264.5
Other long-term debt		—		6.7		—		6.7
Deposits		15.9		—		—		15.9

XML

Note 9 - Property, Plant and Equipment and Construction-in-process

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Property, Plant and Equipment Disclosure [Text Block]

NOTE

9

— PROPERTY, PLANT AND EQUIPMENT AND CONSTRUCTION-IN-PROCESS

Property, plant and equipment

Property, plant and equipment, net, consist of the following:

	December 31,
	2016			2015
	(Dollars in thousands)
Land owned by the Company where the geothermal resource is located	$	31,904		$	31,465
Leasehold improvements		3,848			3,691
Machinery and equipment		152,821			133,457
Land, buildings and office equipment		28,634			29,247
Automobiles		11,161			7,782
Geothermal and recovered energy generation power plants, including geothermal wells and exploration and resource development costs:
United States of America, net of cash grants and impairment charges		1,658,195			1,637,081
Foreign countries		541,626			494,105
Asset retirement cost		8,669			7,961
		2,436,858			2,344,789
Less accumulated depreciation		(880,480	)		(785,454	)
Property, plant and equipment, net	$	1,556,378		$	1,559,335

Depreciation expense for the years ended

December

31,

2016,

2015,

and

2014

amounted to

$94.8

million,

$95.2

million and

$87.9

million, respectively. Depreciation expense for the years ended

December

31,

2016,

2015

and

2014

is net of the impact of the cash grant in the amount of

$5.5

million,

$5.5

million and

$5.3

million, respectively.

U.S. Operations

The net book value of the property, plant and equipment, including construction-in-process, located in the United States was approximately

$1,376.1

million and

$1,335.0

million as of

December

31,

2016

and

2015,

respectively. These amounts as of

December

31,

2016

and

2015

are net of cash grants in the amount of

$138.7

million and

$144.2

million, respectively.

Foreign Operations

The net book value of property, plant and equipment, including construction-in-process, located outside of the United States was approximately

$487.0

million and

$473.1

million as of

December

31,

2016

and

2015,

respectively.

The Company, through its wholly owned subsidiary, OrPower

4,

Inc. (“OrPower

4”)

owns and operates geothermal power plants in Kenya. The net book value of assets associated with the power plants was

$315.0

 million and

$355.8

million as of

December

31,

2016

and

2015,

respectively. The Company sells the electricity produced by the power plants to Kenya Power and Lighting Co. Ltd. (“KPLC”) under a

20

-year PPA.

The Company, through its wholly owned subsidiary, Orzunil I de Electricidad, Limitada (“Orzunil”), owns a power plant in Guatemala. On

January

22,

2014,

Orzunil signed an amendment to the PPA with Instituto Nacional de Electrificacion (“INDE”) a Guatemalan power utility for its Zunil geothermal power plant in Guatemala. The amendment extends the term of the PPA from

2019

to

2034.

The PPA amendment also transfers operation and management responsibilities of the Zunil geothermal field from INDE to the Company for the term of the amended PPA in exchange for a tariff increase. Additionally, INDE exercised its right under the PPA to become a partner in the Zunil power plant with

a

3%

equity interest. The net book value of the assets related to the power plant was

$12.2

million and

$19.2

million at

December

31,

2016

and

2015,

respectively.

The Company, through its wholly owned subsidiary, Ortitlan, Limitada (“Ortitlan”), owns a power plant in Guatemala. The net book value of the assets related to the power plant was

$40.3

million and

$46.0

million at

December

31,

2016

and

2015,

respectively.

Construction-in-process

Construction-in-process consists of the following:

	December 31,
	2016		2015
	(Dollars in thousands)
Projects under exploration and development:
Up-front bonus lease costs	$	17,385	$	26,491
Exploration and development costs		36,359		35,726
Interest capitalized		703		703
		54,447		62,920
Projects under construction:
Up-front bonus lease costs		37,713		27,473
Drilling and construction costs		202,211		150,467
Interest capitalized		12,338		7,975
		252,262		185,915
Total	$	306,709	$	248,835

	Projects under Exploration and Development
	Up-front Bonus Lease Costs			Exploration and Development Costs			Interest Capitalized			Total
	(Dollars in thousands)
Balance at December 31, 2013	$	30,141		$	38,220		$	1,278		$	69,639
Cost incurred during the year		—			19,231			—			19,231
Write off of unsuccessful exploration costs		(3,523	)		(11,474	)		(442	)		(15,439	)
Balance at December 31, 2014		26,618			45,977			836			73,431
Cost incurred during the year		37			10,104			869			11,010
Write off of unsuccessful exploration costs		(164	)		(1,415	)		—			(1,579	)
Transfer of projects under exploration and development to projects under construction		—			(18,940	)		(1,002	)		(19,942	)
Balance at December 31, 2015		26,491			35,726			703			62,920
Cost incurred during the year		1,514			25,165			—			26,679
Write off of unsuccessful exploration costs		(380	)		(2,637	)		—			(3,017	)
Transfer of projects under exploration and development to projects under construction		(10,240	)		(21,895	)		—			(32,135	)
Balance at December 31, 2016	$	17,385		$	36,359		$	703		$	54,447

	Projects under Construction
	Up-front Bonus Lease Costs		Drilling and Construction Costs			Interest Capitalized			Total
	(Dollars in thousands)
Balance at December 31, 2013	$	27,473	$	184,766		$	6,948		$	219,187
Cost incurred during the year		—		132,597			3,206			135,803
Transfer of completed projects to property, plant and equipment		—		(105,126	)		(970	)		(106,096	)
Sale of property, plant and equipment		—		(24,692	)		(911	)		(25,603	)
Balance at December 31, 2014		27,473		187,545			8,273			223,291
Cost incurred during the year		—		140,977			3,556			144,533
Transfer of exploration and development projects to projects under construction		—		18,940			1,002			19,942
Transfer of completed projects to property, plant and equipment		—		(196,995	)		(4,856	)		(201,851	)
Sale of property, plant and equipment		—		—			—			—
Balance at December 31, 2015		27,473		150,467			7,975			185,915
Cost incurred during the year		—		116,247			6,510			122,757
Transfer of exploration and development projects to projects under construction		10,240		21,895			—			32,135
Transafer of completed projects to property, plant and equipment		—		(86,398	)		(2,147	)		(88,545	)
Balance at December 31, 2016	$	37,713	$	202,211		$	12,338		$	252,262

XML

Note 10 - Intangible Assets and Goodwill

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Intangible Assets Disclosure [Text Block]

NOTE

10

— INTANGIBLE ASSETS AND GOODWILL

Intangible assets

amounting to

$52.8

million and

$25.9

million consist mainly of the Company’s power purchase agreements (“PPAs”)

acquired in business combinations, net of accumulated amortization of

$42.8

million and

$38.4

million as of

December

31,

2016

and

2015,

respectively. Amortization expense for the years ended

December

31,

2016,

2015,

and

2014

amounted to

$4.4

million,

$3.3

million, and

$3.3

million, respectively. Additions of intangible assets for the years ended

December

31,

2016,

2015

and

2014,

amounted to

$33.0

million,

$0.5

million and

$0,

respectively. The addition to intangible assets in

2016

relates to the purchase of the Guadeloupe plant (Note

3).

There were

no

disposals of intangible assets in

2016,

2015

and

2014.

Estimated future amortization expense for the intangible assets as of

December

31,

2016

is as follows:

	(Dollars in thousands)
Year ending December 31:
2017	$	5,042
2018		4,912
2019		4,839
2020		4,522
2021		4,522
Thereafter		28,916
Total	$	52,753

Goodwill

Goodwill amounting to

$7.1

million was recorded as a result of the Guadeloupe power plant purchase transaction that was closed in

July

2016

(see Note

3

for more details).

During

2016,

there were

no

additions or adjustments to the carrying value of goodwill except for the impact of currency translation adjustments. The carrying value of goodwill as of

December

31,

2016

is

$6.7

million.

XML

Note 11 - Accounts Payable and Accrued Expenses

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Accounts Payable and Accrued Liabilities Disclosure [Text Block]

NOTE

11

 — ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses consist of the following:

	December 31,
	2016		2015
	(Dollars in thousands)
Trade payables	$	48,309	$	41,364
Salaries and other payroll costs		17,977		14,671
Customer advances		576		2,533
Accrued interest		3,524		8,252
Income tax payable		8,824		11,353
Property tax payable		1,884		3,609
Scheduling and transmission		964		1,547
Royalty accrual		1,639		1,818
Other		7,953		6,808
Total	$	91,650	$	91,955

XML

Note 12 - Long-term Debt and Credit Agreements

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Long-term Debt [Text Block]

NOTE

12

 — LONG-TERM DEBT AND CREDIT AGREEMENTS

Long-term debt consists of notes payable under the following agreements:

	December 31,
	2016			2015
	(Dollars in thousands)
Limited and non-recourse agreements:
Loans:
Non-recourse:
Other loans	$	6,368		$	-
Limited recourse:
Loan agreement with OPIC (the Olkaria III power plant)		246,630			264,624
Loan agreement with Banco Industrial S.A. and Westrust Bank (International) Limited		36,750			40,250
Senior Secured Notes:
Non-recourse:
Ormat Funding Corp. ("OFC")		17,026			29,968
OrCal Geothermal Inc. ("OrCal")		35,181			43,332
Don A. Campbell 1 ("DAC1")		92,361
Limited recourse:
OFC 2 LLC ("OFC 2")		247,232			261,959
		681,548			640,133
Less current portion		(53,729	)		(51,425	)
Non current portion	$	627,819		$	588,708
Full recourse agreements:
Senior unsecured bonds	$	204,332		$	249,981
Loans from institutional investors		3,333			6,667
Loan agreements with DEG (the Olkaria III and IV power plants)		65,789			23,684
Loan from a commercial bank		1,529			-
Revolving credit lines with banks		-			-
		274,983			280,332
Less current portion		(12,242	)		(11,229	)
Non current portion	$	262,741		$	269,103

Loan Agreement

with

Banco Industrial S.A. and Westrust Bank (International) Limited

On

July

31,

2015,

one

of our indirect wholly-owned subsidiaries, Ortitlản, Limitada, obtained a

12

-year secured term loan in the principal amount of

$42.0

million for the

20

MW Amatitlan power plant in Guatemala. Under the credit agreement with Banco Industrial S.A. and Westrust Bank (International) Limited, we can expand the Amatitlan power plant with financing to be provided either via equity, additional debt from Banco Industrial S.A. or from other lenders, subject to certain limitations on expansion financing in the credit agreement.

The loan is payable in

48

quarterly payments commencing

September

30,

2015.

The loan bears interest at a rate

per annum

equal to of the sum of the LIBO Rate (which cannot be lower than

1.25%)

plus a margin of (i)

4.35%

as long as the Company’s guaranty of the loan (as described below) is outstanding or (ii)

4.75%

otherwise. Interest is payable quarterly, on

March

30,

June

30,

September

30

and

December

30

of each year, on the stated maturity date of the loan and on any prepayment or payment of the loan. The loan must be prepaid on the occurrence of certain events, such as casualty, condemnation, asset sales and expansion financing not provided by the lenders under the credit agreement, among others. The loan

may

be voluntarily prepaid if certain conditions are satisfied, including payment of a premium (ranging from

100

-

50

basis points) if prepayment occurs prior to the

eighth

anniversary of the loan.

There are various restrictive covenants under the Amatitlan credit agreement. These include, among others, (i) a financial covenant to maintain a Debt Service Coverage Ratio (as defined in the credit agreement) of not less than

1.15

to

1.00

as of the last day of any fiscal quarter and (ii) limitations on Restricted Payments (as defined in the credit agreement) that among other things would limit dividends that could be paid to us unless the historical and projected Debt Service Coverage Ratio is not less than

1.25

to

1.00

for the

four

fiscal quarterly periods (calculated as a single accounting period).

As of

December

31,

2016,

the actual historical and projected

12

-month Debt Service Coverage Ratio was

1.87

and

1.92,

respectively. The credit agreement includes various events of default that would permit acceleration of the loan (subject in some cases to grace and cure periods). These include, among others, a Change of Control (as defined in the credit agreement) and failure to maintain certain required balances in debt service and maintenance reserve accounts. The credit agreement includes certain equity cure rights for failure to maintain the Debt Service Coverage Ratio and the minimum amounts required in the debt service and maintenance reserve accounts.

The loan is secured by substantially all the assets of the borrower and a pledge of all of the membership interests of the borrower.

The Company has guaranteed payment of all obligations under the credit agreement and related financing documents. The guaranty is limited in the sense that the Company is only required to pay the guaranteed obligations if a “trigger event” occurs. A trigger event is the occurrence and continuation of a default by Instituto Nacional de Electricidad (“INDE”) in its payment obligations under the power purchase agreement for the Amatitlàn power plant or a refusal by INDE to receive capacity and energy sold under that power purchase agreement. Our obligations under the guaranty

may

be terminated prior to payment in full of the guaranteed obligations under certain circumstances described in the guaranty. If our guaranty is terminated early, the interest rate payable on the loan would increase as described above.

As of

December

31,

2016,

$36.8

million of this loan is outstanding.

Finance Agreement with OPIC (the Olkaria III Complex)

On

August

 

23,

2012,

the Company’s wholly owned subsidiary, OrPower

4

entered into a Finance Agreement with Overseas Private Investment Corporation (“OPIC”), an agency of the United States government, to provide limited-recourse senior secured debt financing in an aggregate principal amount of up to

$310.0

million (the “OPIC Loan”) for the refinancing and financing of the Olkaria III geothermal power complex in Kenya. The Finance Agreement was amended on

November

9,

2012.

The OPIC Loan is comprised of up to

three

tranches:

• Tranche I in an aggregate principal amount of $85.0 million, which was drawn in November 2012, was used to prepay approximately $20.5 million (plus associated prepayment penalty and breakage costs of $1.5 million) of the DEG Loan, as described below. The remainder of Tranche I proceeds was used for reimbursement of prior capital costs and other corporate purposes.

• Tranche II in an aggregate principal amount of $180.0 million was used to fund the construction and well field drilling for the expansion of the Olkaria III geothermal power complex (“Plant 2”). In November 2012, an amount of $135.0 million was disbursed under this Tranche II, and in February 2013, the remaining $45.0 million was distributed under this Tranche II.

• Tranche III in an aggregate principal amount of $45.0 million was used to fund the construction of Plant 3 of the Olkaria III complex. In November 2013, an amount of $45.0 million was disbursed under this Tranche.

I

n

July

2013,

we completed the conversion of the interest rate applicable to both Tranche I and Tranche II from a floating interest rate to a fixed interest rate. The average fixed interest rate for Tranche I, which has an outstanding balance as of

December

31,

2016

of

$66.0

million and matures on

December

15,

2030,

and Tranche II, which has an outstanding balance as of

December

31,

2016

of

$142.9

million and matures on

June

15,

2030,

is

6.31%.

In

November

2013,

we fixed the interest rate for Tranche III. The fixed interest rate for Tranche III, which has an outstanding balance as of

December

31,

2016

of

$37.6

million and matures on

December

15,

2030,

is

6.12%.

OrPower

4

has a right to make voluntary prepayments of all or a portion of the OPIC Loan subject to prior notice, minimum prepayment amounts,

and a prepayment premium of

2.0%

in the

first

two

years after the Plant

2

commercial operation date, declining to

1%

in the

third

year after the Plant

2

commercial operation date, and without premium thereafter, plus a redemption premium. In addition, the OPIC Loan is subject to customary mandatory prepayment in the event of certain reductions in generation capacity of the power plants, unless such reductions will not cause the projected ratio of cash flow to debt service to fall below

1.7.

The OPIC Loan is secured by substantially all of OrPower

4

’

s assets and by a pledge of all of the equity interests in OrPower

4.

The finance agreement includes customary events of default, including failure to pay any principal, interest or other amounts when due, failure to

comply with covenants, breach of representations and warranties, non-payment or acceleration of other debt of OrPower

4,

bankruptcy of OrPower

4

or certain of its affiliates, judgments rendered against OrPower

4,

expropriation, change of control, and revocation or early termination of security documents or certain project-related agreements, subject to various exceptions and notice, cure and grace periods.

The repayment of the remaining outstanding DEG Loan (see

“

Full-Recourse Third-Party Debt”

below) in the amount of approximately

$15.8

million as of

December

31,

2016,

has been subordinated to the OPIC Loan.

There are various restrictive covenants under the OPIC Loan, which include a required historical and projected

12

-month DSCR of not less than

1.4

(measured as of

March

15,

June

15,

September

15

and

December

15

of each year). If OrPower

4

fails to comply with these financial ratios it will be prohibited from making distributions to its shareholders. In addition, if the DSCR falls below

1.1,

subject to certain cure rights, such failure will constitute an event of default by OrPower

4.

This covenant in respect of Tranche I became effective on

December

15,

2014.

As of

December

31,

2016,

the actual historical and projected

12

-month DSCR was

2.69

and

2.96,

respectively.

As of

December

31,

2016,

$246.6

million of the OPIC Loan was outstanding.

Debt service reserve

As required under the terms of the OPIC Loan, OrPower

4

maintains an account which

may

be funded by cash or backed by letters of credit in an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the OPIC Loan in the following

six

months. This restricted cash account is classified as current in the consolidated balance sheets. As of

December

31,

2016

and

2015,

the balance of the account

was

$4.3

million and

$7.2

million, respectively. In addition, as of

December

31,

2016,

part of the required debt service reserve was backed by a letter of credit in the amount of

$17.3

million (see Note

23).

Well drilling reserve

As required under the terms of the OPIC Loan, OrPower

4

may

be required to maintain an account which

may

be funded by cash or backed by letters of credit to reserve funds for future well drilling, based on determination upon the completion of the expansion work

.

OFC Senior Secured Notes

In

February

2004,

OFC, a wholly owned subsidiary, issued

$190.0

million of

8.25%

Senior Secured Notes (“OFC Senior Secured Notes”) and received net cash proceeds of approximately

$179.7

million, after deduction of issuance costs of approximately

$10.3

million. The OFC Senior Secured Notes have a final maturity of

December

30,

2020.

Principal and interest on the OFC Senior Secured Notes are payable in semi-annual payments. The OFC Senior Secured Notes are collateralized by substantially all of the assets of OFC and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC. There are various restrictive covenants under the OFC Senior Secured Notes, which include limitations on additional indebtedness of OFC and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OFC.  In addition, there are restrictions on the ability of OFC to make distributions to its shareholders, which include a required historical and projected

12

-month DSCR of not less than

1.25

(measured semi-annually as of

June

 

30

and

December

 

31

of each year). If OFC fails to comply with the DSCR ratio it will be prohibited from making distributions to its shareholders. The Company believes that the transition to variable energy prices under the Ormesa and Mammoth PPAs and the impact of the currently low natural gas prices on the revenues under these PPAs

may

cause OFC to not meet the DSCR ratio requirements for making distributions, but it does not believe that there will be an event of default by OFC. OFC is only required to measure these covenants on a semi-annual basis and as of

December

31,

2016,

the last measurement date of the covenants, the actual historical

12

-month DSCR was

1.25

and the pro-forma

12

-month DSCR was

1.38.

There were

$17.0

million and

$30.0

million of OFC Senior Secured Notes outstanding as of

December

31,

2016

and

December

31,

2015,

respectively.

In

February

2013,

the Company repurchased

$12.8

million aggregate principal amount of OFC Senior Secured Notes from the OFC noteholders and recognized a gain of approximately

$0.8

million in the

first

quarter of

2013.

In

January

2014,

the Company repurchased

$13.2

million aggregate principal amount of OFC Senior Secured Notes from the OFC noteholders and recognized a gain of approximately

$0.3

million in the

first

quarter of

2014.

In

June

2015,

the Company repurchased

$30.6

million aggregate principal amount of OFC Senior Secured Notes from the OFC noteholders and recognized a loss of approximately

$1.7

million in the

second

quarter of

2015.

In

September

2016,

the Company repurchased

$6.8

million aggregate principal amount of OFC Senior Secured Notes from the OFC noteholders and recognized a loss of

$0.6

million, in the

third

quarter of

2016.

OFC

may

redeem the OFC Senior Secured Notes, in whole or in part, at any time, at redemption price equal to the principal amount of the OFC Senior Secured Notes to be redeemed plus accrued interest, premium and liquidated damages, if any, plus a “make-whole” premium. Upon certain events, as defined in the indenture governing the OFC Senior Secured Notes, OFC

may

be required to redeem a portion of the OFC Senior Secured Notes at a redemption price ranging from

100%

to

101%

of the principal amount of the OFC Senior Secured Notes being redeemed plus accrued interest, premium and liquidated damages, if any

.

Debt service reserve

As required under the terms of the OFC Senior Secured Notes, OFC maintains an account which

may

be funded by cash or backed by letters of credit (see below) in an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the OFC Senior Secured Notes in the following

six

months. This restricted cash account is classified as current in the consolidated balance sheets. As of each of

December

31,

2016

and

2015,

the balance of such account

was

$2.1

million and

$1.4

million, respectively. In addition, as of each of

December

31,

2016

and

2015,

part of the required debt service reserve was backed by a letter of credit in the amount of

$11.5

million and

$11.6

million (see Note

23),

respectively.

OrCal Senior Secured Notes

In

December

2005,

OrCal, a wholly owned subsidiary, issued

$165.0

million,

6.21%

Senior Secured Notes (“OrCal Senior Secured Notes”) and received net cash proceeds of approximately

$161.1

million, after deduction of issuance costs of approximately

$3.9

million, which have been included in deferred financing costs in the consolidated balance sheet. The OrCal Senior Secured Notes have been rated BBB- by Fitch Ratings. The OrCal Senior Secured Notes have a final maturity of

December

30,

2020.

Principal and interest on the OrCal Senior Secured Notes are payable in semi-annual payments. The OrCal Senior Secured Notes are collateralized by substantially all of the assets of OrCal, and those of its subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OrCal. There are various restrictive covenants under the OrCal Senior Secured Notes, which

include limitations on additional indebtedness of OrCal and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OrCal. In addition, there are restrictions on the ability of OrCal to make distributions to its shareholders, which include a required historical and projected

12

-month DSCR of not less than

1.25

(measured semi-annually as of

June

 

30

and

December

 

31

of each year). If OrCal fails to comply with the DSCR ratio it will be prohibited from making distributions to its shareholders. OrCal is only required to measure these covenants on a semi-annual basis and as of

December

31,

2016,

the last measurement date of the covenants, the actual historical

12

-month DSCR was

1.77

and the pro-forma

12

-month DSCR was

2.57.

There was

$35.2

million and

$43.3

million of OrCal Senior Secured Notes outstanding as of

December

31,

2016

and

December

31,

2015,

respectively.

OrCal

may

redeem the OrCal Senior Secured Notes, in whole or in part, at any time at a redemption price equal to the principal amount of the OrCal Senior Secured Notes to be redeemed plus accrued interest, and a “make-whole” premium. Upon certain events, as defined in the indenture governing the OrCal Senior Secured Notes, OrCal

may

be required to redeem a portion of the OrCal Senior Secured Notes at a redemption price of

100%

of the principal amount of the OrCal Senior Secured Notes being redeemed plus accrued interest

.

Debt service reserve

As required under the terms of the OrCal Senior Secured Notes, OrCal maintains an account which

may

be funded by cash or backed by letters of credit (see below) in an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the OrCal Senior Secured Notes in the following

six

months. This restricted cash account is classified as current in the consolidated balance sheets. As of

December

31,

2016

and

2015,

the balance of such account was

$1.9

million and

$1.6

million, respectively. In addition, as of

December

31,

2016

and

2015,

part of the required debt service reserve was backed by a letter of credit in the amount of

$4.6

million and

$5.5

million, respectively (see Note

23).

OFC

2

Senior Secured Notes

In

September

2011,

the Company

’s subsidiary OFC

2

and its wholly owned project subsidiaries (collectively, the “OFC

2

Issuers”) entered into a note purchase agreement (the “Note Purchase Agreement”) with OFC

2

Noteholder Trust, as purchaser, John Hancock Life Insurance Company (U.S.A.), as administrative agent, and the DOE, as guarantor, in connection with the offer and sale of up to

$350.0

million aggregate principal amount of OFC

2

Senior Secured Notes (“OFC

2

Senior Secured Notes”) due

December

31,

2034.

Subject to the fulfillment of customary and other specified conditions precedent, the OFC

2

Senior Secured Notes

may

be issued in up to

six

distinct series associated with the phased construction (Phase I and Phase II) of the Jersey Valley, McGinness Hills and Tuscarora geothermal power plants, which are owned by the OFC

2

Issuers.

The OFC

2

Senior Secured Notes will mature and the principal amount of the OFC

2

Senior Secured Notes will be payable in equal quarterly installments and in any event not later than

December

31,

2034.

Each series of notes will bear interest at a rate calculated based on a spread over the Treasury yield curve that will be set at least

ten

business days prior to the issuance of such series of notes. Interest will be payable quarterly in arrears. The DOE will guarantee payment of

80%

of principal and interest on the OFC

2

Senior Secured Notes pursuant to Section

1705

of Title XVII of the Energy Policy Act of

2005,

as amended. The conditions precedent to the issuance of the OFC

2

Senior Secured Notes includes certain specified conditions required by the DOE in connection with its guarantee of the OFC

2

Senior Secured Notes.

On

October

31,

2011,

the Issuers completed the sale of

$151.7

million in aggregate principal amount

of

4.687%

Series A Notes due

2032

(the “Series A Notes”). The net proceeds from the sale of the Series A Notes, after deducting transaction fees and expenses, were approximately

$141.1

million, and were used to finance a portion of the construction costs of Phase I of the McGinness Hills and Tuscarora power plants and to fund certain reserves. Principal and interest on the Series A Notes are payable quarterly in arrears on the last day of

March,

June,

September

and

December

of each year.

On

June

20,

2014,

Phase

1

of Tuscarora Facility achieved Project Completion under the OFC

2

Note Purchase

Agreement. In accordance with the terms of the Note Purchase Agreement and following recalibration of the financing assumptions, the loan amount was adjusted through a principal prepayment of

$4.3

million.

On

August

29,

2014,

OFC

2

signed a

$140.0

million loan under the OFC

2

Senior Secured Notes to finance the construction of the McGinness Hills

2

Phase project. This drawdown is the last tranche (Series C notes) under the Note Purchase Agreement with John Hancock Life Insurance Company and guaranteed by the DOE’s Loan Programs Office in accordance with and subject to the DOE's Loan Guarantee Program under Section

1705

of Title XVII of the Energy Policy Act of

2005.

The

$140.0

million loan, which matures in

December

2032,

carries a

4.61%

coupon with principal to be repaid on a quarterly basis. The OFC

2

Senior Secured Notes, which include loans for the Tuscarora, Jersey Valley and McGinness Hills complexes, are rated “BBB” by Standard & Poor's.

In connection with the anticipated drawdown, on

August

13,

2014,

the Company entered into an on-the-run interest rate lock agreement with a financial institution with a termination date of

August

15,

2014.

This on-the-run interest rate lock agreement had a notional amount of

$140.0

million and was designated by us

as a cash flow hedge. The objective of this cash flow hedge was to eliminate the variability in the changes in the

10

-year U.S. Treasury rate as that is

one

of the components in the annual interest rate of the OFC

2

loan that was forecasted to be fixed on

August

15,

2014.

As such, the Company hedged the variability in total proceeds attributable to changes in the

10

-year U.S. Treasury rate for the forecasted issuance of fixed rate OFC

2

loan. On

August

18,

2014,

the settlement date, the Company paid

$1.5

million to the counterparty of the on-the-run interest rate lock agreement.

The Company concluded that the cash flow hedge was fully effective with no ineffective portion and no amounts excluded from the effectiveness testing, thus

, in

2014,

the total loss from the cash flow hedge was fully recognized in “Loss in respect of derivatives instruments designated for cash flow hedge” under other comprehensive income of

$0.9

million noted above, which was net of related taxes of

$0.6

million. The cash flow hedge loss recorded is amortized over the life of the OFC

2

loan using the effective interest method. In

2016

and

2015,

the Company reclassified

$0.1

million, each year, of the loss from “Accumulated other comprehensive income (loss)” into interest expense.

The OFC

2

Senior Secured Notes are collateralized by substantially all of the assets of OFC

2

and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC

2.

There are various restrictive covenants under the OFC

2

Senior Secured Notes, which include limitations on additional indebtedness of OFC

2

and its wholly owned subsidiaries.

 Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OFC

2.

  In addition, there are restrictions on the ability of OFC

2

to make distributions to its shareholders.

Among other things, the distribution restrictions include a historical debt service coverage ratio requirement of at least

1.2

(on a blended basis for all OFC

2

power plants), measured, at the time of any proposed distribution, over each of the

two

six

-months periods comprised of distinct consecutive fiscal quarters immediately preceding the proposed distribution, and a projected future debt service coverage ratio requirement of at least

1.5

(on a blended basis for all OFC

2

power plants), measured, at the time of any proposed distribution, over each of the

two

six

-months periods comprised of distinct consecutive fiscal quarters immediately following such proposed distribution.

As of

December

31,

2016,

our historical debt service coverage ratio was 

2.49

and

2.09,

 respectively for each of the

two

six

-month periods, and our projected future debt service coverage ratio was

1.98

and

2.05,

respectively for each of the

two

six

-month periods.

There were $

247.2

million and

$262.0

million of OFC

2

Senior Secured Notes outstanding as of

December

31,

2016

and

December

31,

2015,

respectively.

The Company provided a guarantee in connection with the issuance of the Series A and C Notes. One trigger event is the failure of any facility financed by the relevant Series of OFC

2

Senior Secured Notes to reach completion and meet certain operational performance levels (the non-performance trigger) which gives rise to a prepayment obligation on the OFC

2

Senior Secured Notes. The other trigger event is a payment default on the OFC

2

Senior Secured Notes or the occurrence of certain fundamental defaults that result in the acceleration of the OFC

2

Senior Secured Notes, in each case that occurs prior to the date that the relevant facility(ies) financed by such OFC

2

Senior Secured Notes reaches completion and meets certain operational performance levels. A demand on the Company

’s guarantee based on the non-performance trigger is limited to an amount equal to the prepayment amount on the OFC

2

Senior Secured Notes necessary to bring the OFC

2

Issuers into compliance with certain coverage ratios. A demand on the Company’s guarantee based on the other trigger event is not so limited.

Debt service reserve

; other restricted funds

Under the terms of the OFC

2

Senior Secured Notes, OFC

2

is required to maintain a debt service reserve and certain other reserves, as follows:

(i) A debt service reserve account which may be funded by cash or backed by letters of credit (see below) in an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the OFC 2 Senior Secured Notes in the following six months. This restricted cash account is classified as current in the consolidated balance sheet. As of December 31, 2016, part of the required debt service reserve was backed by a letter of credit in the amount of $21.0 million (see Note 23).

(ii) A performance level reserve account, intended to provide additional security for the OFC 2 Senior Secured Notes, which may be funded by cash or backed by letters of credit. This reserve builds up over time and reduces gradually each time the project achieves certain milestones. Upon issuance of the Series A Notes, this reserve was funded in the amount of $28.0 million. As of December 31, 2016, the balance of such account was $9.7 million and there was no requirement for an additional letter of credit to be issued. 

(iii) Under the terms of the OFC 2 Senior Secured Notes, OFC 2 is also required to maintain a well field drilling and maintenance reserve that builds up over time and is dedicated to costs and expenses associated with drilling and maintenance of the project's well field, which may be funded by cash or backed by letters of credit.

(iv) A performance level reserve account for McGinness Hills Phase II, intended to provide additional security for the OFC 2 Senior Secured Notes, which may be funded by cash or backed by letters of credit. Upon issuance of the Series C Notes, this reserve was funded in the amount of $53.4 million in letter of credit. As of December 31, 2016, there was no requirement for an additional letter of credit to be issued.

Don A. Campbell Senior

Secured Notes — Non-Recourse

On

November

29,

2016,

a Company subsidiary, ORNI

47

LLC (“ORNI

47”),

entered into a note purchase agreement (the “Note Purchase Agreement”) with MUFG Union Bank, N.A., as collateral agent, Munich Reinsurance America, Inc. and Munich American Reassurance Company (the “Purchasers”) pursuant to which ORNI

47

issued and sold to the Purchasers

$92.5

million aggregate principal amount of its

4.03%

Senior Secured Notes due

September

27,

2033

(the “Notes”) in a private placement exempt from the registration requirements of the Securities Act of

1933,

as amended. ORNI

47

is the owner of the Don A. Campbell Phase I (“DAC

1”)

geothermal power plant, and part of ORPD.

The net proceeds from the sale of the Notes, after deducting certain transaction expenses and the funding of a debt service reserve account, were approximately $

87.1

million and ORNI

47

intends to use the proceeds from the sale of the Notes to refinance the development and construction costs of the DAC

1

geothermal power plant, which were originally financed using equity.

ORNI

47

will pay a scheduled amount of principal of the Notes beginning on

December

27,

2016

and then quarterly, on the

27th

day of each

March,

June,

September

and

December,

until the Notes mature.

The Notes constitute senior secured obligations of ORNI

47

and are secured by all of the assets of ORNI

47.

Under the Note Purchase Agreement, ORNI

47

may

prepay at any time all, or from time to time any part of, the Notes in an amount equal to at least

$2

million or such lesser amount as

may

remain outstanding under the Notes at

100%

of the principal amount to be prepaid plus the applicable make-whole amount determined for the prepayment date with respect to such principal amount. Upon the occurrence of a Change of Control (as defined in the Note Purchase Agreement), ORNI

47

must make an offer to each holder of Notes to repurchase all of the holder

’s Notes at

101%

of the aggregate principal amount of Notes to be repurchased plus accrued and unpaid interest, if any, on the Notes to be repurchased to, but not including, the date of repurchase. Each holder of Notes

may

accept such offer in whole or in part. In certain events, including certain asset sales outside the ordinary course of business, ORNI

47

must make mandatory prepayments of the Notes at

100%

of the principal amount to be prepaid. The Note Purchase Agreement requires ORNI

47

to comply with certain covenants, including, among others, restrictions on the incurrence of indebtedness or liens, amendment or modification of material project documents, the ability of ORNI

47

to merge or consolidate with another entity. The Note Purchase Agreement also contains customary events of default.  In addition, there are restrictions on the ability of ORNI

47

to make distributions to its shareholders, which include a required historical and projected Debt Service Coverage Ratio not less than

1.20

for the

four

fiscal quarterly periods. As of

December

31,

2016,

the projected Debt Service Coverage Ratio was

1.85.

As of

December

31,

2016,

$92.4

million is outstanding under the DAC

1

Loan.

Senior Unsecured Bonds

In

August

2010,

the Company entered into a trust instrument governing the issuance of, and accepted subscriptions for, an aggregate principal amount of approximately

$142.0

million of senior unsecured bonds (the “Bonds”). Subject to early redemption, the principal of the Bonds was repayable in a single bullet payment upon the final maturity of the Bonds on

August

1,

2017.

The Bonds bore interest at a fixed rate of

7%,

payable semi-annually

.

In

February

2011,

the Company accepted subscription for an aggregate principal amount of approximately

$107.5

million of additional senior unsecured bonds (the “Additional Bonds”) under

two

addendums to the trust instrument. The terms and conditions of the Additional Bonds were identical to the original Bonds. The Additional Bonds were issued at a premium which reflects an effective fixed interest of

6.75%.

In

September

 

2016,

the Company concluded an auction

tender

and accepted subscriptions for

$204

million aggregate principal amount of

two

tranches (Series

2

approximately

$67

million and Series

3

approximately

$137

million) of senior unsecured bonds. The proceeds from the senior unsecured bonds were used on

September

29,

2016,

to prepay the Company

’s

$250

million senior secured bonds that were payable on

August

1,

2017.

The senior unsecured bonds,

 which were issued on

September

14,

2016,

have an outstanding aggregate principal amount of approximately

$204.0

million consisting of

two

tranches (approximately

$67

million principal amount of Series

2

and approximately

$137

million principal amount of Series

3).

The Series

2

Bonds will mature in

September

2020

and bear interest at a fixed rate of

3.7%

per annum, payable semi-annually. The Series

3

Bonds will mature in

September

2022

and bear interest at a fixed rate of

4.45%

per annum, payable semi-annually. The Bonds will be repaid at maturity in a single bullet payment, unless earlier prepaid by Ormat pursuant to the terms and conditions of the trust instrument that governs the Bonds. Both tranches received a rating of ilA+ from Maloot S&P in Israel with a stable outlook.

Loans from institutional investors

In

July

2009,

the Company entered into a

6

-year loan agreement of

$20.0

million with a group of institutional investors (the “First Loan”). The First Loan matured on

July

16,

2015,

was payable in

12

semi-annual installments, which commenced on

January

16,

2010,

and bore interest of

6.5%

.

As of

December

31,

2015,

this loan was fully repaid.

In

July

2009,

the Company entered into an

8

-year loan agreement of

$20.0

million with another group of institutional investors (the “Second Loan”). The Second Loan matures on

August

1,

2017,

is payable in

12

semi-annual installments, which commenced on

February

1,

2012,

and bears interest at

6

-month LIBOR plus

5.0%

.

As of

December

31,

2016,

$3.3

million was outstanding under this loan.

In

November

2010,

the Company entered into a

6

-year loan agreement of

$20.0

million with a group of institutional investors (the “Third Loan”). The Third Loan maturity date was

November

16,

2016,

was payable in

ten

semi-annual installments, which commenced on

May

16,

2012,

and bore interest of

5.75%

.

In

October

2015,

the Company prepaid this term loan in full and in accordance with the loan’s prepayment provisions. The total prepayment amount was

$6.2

million comprising principal and interest.

Loan Agreement

s

with DEG

(the Olkaria III Complex

)

In

March

2009,

the Company

’s wholly owned subsidiary, OrPower

4,

entered into a project financing loan of

$105.0

million to refinance its investment in Phase I of the Olkaria III complex located in Kenya (the “DEG Loan”). The DEG Loan was provided by a group of European Development Finance Institutions (“DFIs”) arranged by DEG — Deutsche Investitions — und Entwicklungsgesellschaft mbH (“DEG”). The

first

disbursement of

$90.0

million occurred on

March

23,

2009

and the

second

disbursement of

$15.0

million occurred on

July

10,

2009.

The DEG Loan will mature on

December

15,

2018,

and is payable in

19

equal semi-annual installments, commencing

December

15,

2009.

Interest on the DEG Loan is variable based on

6

-month LIBOR plus

4.0%

and OrPower

4

had the option to fix the interest rate upon each disbursement. Upon the

first

disbursement, the Company fixed the interest rate on

$77.0

million of the DEG Loan at

6.90%.

As of

December

31,

2016,

$15.8

million is outstanding under the DEG Loan (out of which

$10.8

million bears interest at a fixed rate).

In

October

2012,

OrPower

4,

DEG and the parties thereto

amended and restated the DEG Loan agreement (the “

DEG Amendment”

). The DEG Amendment became effective on

November

9,

2012

upon the execution by OrPower

4

of the Tranche I and Tranche II Notes and the related disbursements of the proceeds thereof under the OPIC Finance Agreement (as described above). The amended and restated DEG Loan Agreement provides for: (i) the prepayment in full of

two

loans thereunder in the total principal amount of approximately

$20.5

million; (ii) the release and discharge of all collateral security previously provided by OrPower

4

to the secured parties under the DEG Loan agreement and the substitution of the Company’

s guarantee of OrPower

4’

s payment and certain other performance obligations in lieu thereof; and (iii) the establishment of a LIBOR floor of

1.25%

in respect of

one

of the loans under the DEG Loan agreement, and (iv) the elimination of most of the affirmative and negative covenants under the DEG Loan agreement and certain other conforming provisions to take into account OrPower

4’

s execution of the OPIC Finance Agreement and its obligations thereunder.

On

October

20,

2016,

OrPower

4

entered into a new

$50

million subordinated facility agreement with

DEG (the “DEG

2

Facility Agreement”) and on

December

21,

2016,

OrPower

4

completed a drawdown of the full loan amount of

$50

million, with a fixed interest rate of

6.28%

for the duration of the loan (the “DEG

2

Loan”). The DEG

2

Loan will be repaid in

20

equal semi-annual principal installments commencing

December

21,

2018,

with a final maturity on

June

21,

2028.

The DEG

2

Loan is intended for the refinance of Plant

4

of the Olkaria III Complex, which was originally financed using equity and is subordinated to the senior loan provided by OPIC for Plants

1

-

3

of the complex. The loan is guaranteed by the Company.

Under the DEG

2

Facility Agreement, OrPower

4

may

prepay at any time all, or from time to time any part of the DEG

2

Loan in an amount equal to at least

$5

million or such lesser amount as

may

remain outstanding under the DEG

2

Loan at

100%

of the principal amount to be prepaid plus the applicable make-whole amount and certain prepayment premium amount determined for the prepayment date with respect to such principal amount. In certain events, OrPower

4

must make mandatory prepayments of the DEG

2

Loan at

100%

of the principal amount to be prepaid

plus the applicable make-whole amount and certain prepayment premium amount determined for the prepayment date with respect to such principal amount. The DEG

2

Facility Agreement requires OrPower

4

to comply with certain covenants, including, among others, restrictions on the incurrence of indebtedness or liens. The Facility Agreement also contains customary events of default.

As of

December

31,

2016,

$50.0

million is outstanding under the DEG

2

Loan.

Revolving credit lines with commercial banks

As of

December

31,

2016,

the Company has credit agreements with

eight

commercial banks for an aggregate amount of

$524.8

million (including

$60.0

million from Union Bank, N.A. (“Union Bank”) and

$35.0

million from HSBC), see below. Under the terms of these credit agreements, the Company, or its Israeli subsidiary, Ormat Systems, can request: (i) extensions of credit in the form of loans and/or the issuance of

one

or more letters of credit in the amount of up to

$215.0

million; and (ii) the issuance of

one

or more letters of credit in the amount of up to

$309.8

million. The credit agreements mature between end of

March,

2017

and

July

2019.

Loans and draws under the credit agreements or under any letters of credit will bear interest at the respective bank’s cost of funds plus a margin.

As of

December

31,

2016,

no

loans were outstanding, and letters of credit with an aggregate stated amount

of

$341.6

million were issued and outstanding under such credit agreements.

Credit Agreements

Credit agreement with Union Bank

In

February

 

2012,

the Company’s wholly owned subsidiary, Ormat Nevada Inc. (“Ormat Nevada”), entered into an amended and restated credit agreement with Union Bank. Under the amended and restated agreement, the credit termination date was extended to

February

 

7,

2014

(which was subsequently extended to

March

31,

2014

pursuant to Amendment No.

1

to the agreement and then to

June

30,

2017),

and the aggregate amount available under the credit agreement was increased from

$39.0

million to

$60.0

million. The facility is limited to the issuance, extension, modification or amendment of letters of credit. Union Bank is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that

may,

from time to time in the future, join the credit agreement as parties thereto. In connection with this transaction, the Company entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which the Company agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured. There are various restrictive covenants under the credit agreement, which include a requirement to comply with the following financial ratios, which are measured quarterly: (i) a

12

-month debt to EBITDA ratio not to exceed

4.5;

(ii) 

12

-month DSCR of not less than

1.35;

and (iii) distribution leverage ratio not to exceed

2.0.

As of

December

31,

2016:

(i) the actual

12

-month debt to EBITDA ratio was

2.95;

(ii) the

12

-month DSCR was

2.54;

and (iii) the distribution leverage ratio was

0.81.

In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of Union Bank. As of

December

31,

2016,

letters of credit in the aggregate amount of

$32.6

million remain issued and outstanding under this credit agreement with Union Bank.

Credit agreement with

HSBC

In

May

 

2013,

Ormat Nevada, entered into a credit agreement with HSBC Bank USA, N.A for

one

year with annual renewals. The current expiration date of the facility under this credit agreement is

December

31,

2017.

The aggregate amount available under the credit agreement was increased by

$10

million to

$35.0

million. This credit line is limited to the issuance, extension, modification or amendment of letters of credit and

$10.0

million out of this credit line for working capital needs. HSBC is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that

may,

from time to time in the future, join the credit agreement as parties thereto. In connection with this transaction, we entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which we agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured. There are various restrictive covenants under the credit agreement, including a requirement to comply with the following financial ratios, which are measured quarterly: (i) a

12

-month debt to EBITDA ratio not to exceed

4.5;

(ii) 

12

-month DSCR of not less than

1.35;

and (iii) distribution leverage ratio not to exceed

2.0.

As of

December

31,

2016:

(i) the actual

12

-month debt to EBITDA ratio was

2.95;

(ii) the

12

-month DSCR was

2.54;

and (iii) the distribution leverage ratio was

0.81.

In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of HSBC. As of

December

31,

2016,

letters of credit in the aggregate amount of

$23.2

million remain issued and outstanding under this credit agreement.

Restrictive covenants

The Company

’s obligations under the credit agreements, the loan agreements, and the trust instrument governing the bonds, described above, are unsecured, but are subject to a negative pledge in favor of the banks and the other lenders and certain other restrictive covenants. These include, among other things, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any

third

party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of our assets, or a change of control in our ownership structure. Some of the credit agreements, the term loan agreements, as well as the trust instrument contain cross-default provisions with respect to other material indebtedness owed by us to any

third

party. In some cases, the Company has agreed to maintain certain financial ratios, which are measured quarterly, such as: (i) equity of at least

$600.0

million and in no event less than

25%

of total assets; (ii)

12

-month debt, net of cash, cash equivalents marketable securities and short-term bank deposits to Adjusted EBITDA ratio not to exceed

6;

and (iii) dividend distribution not to exceed

35%

of net income for that year. As of

December

31,

2016:

(i) total equity was

$1,170.0

million and the actual equity to total assets ratio was

47.53%,

and (ii) the

12

-month debt, net of cash, cash equivalents marketable securities and short-term bank deposits to Adjusted EBITDA ratio was

2.32.

During the year ended

December

31,

2016,

the Company distributed interim dividends in an aggregate amount of

$25.7

million.

Future minimum payments

Future minimum payments under long-term obligations, excluding revolving credit lines with commercial banks, as of

December

31,

2016

are as follows:

	(Dollars in thousands)
Year ending December 31:
2017	$	65,971
2018		64,805
2019		59,146
2020		126,870
2021		46,579
Thereafter		593,161
Total	$	956,532

XML

Note 13 - Puna Power Plant Lease Transactions

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Leases of Lessee Disclosure [Text Block]

NOTE

13

— PUNA POWER PLANT LEASE TRANSACTIONS

In

2005,

the Company

’s wholly owned subsidiary in Hawaii, Puna Geothermal Ventures (“PGV”), entered into transactions involving the original geothermal power plant of the Puna complex located on the Big Island (the “Puna Power Plant”

).

Pursuant to a

31

-year head lease (the “Head Lease

”), PGV leased the Puna Power Plant to an unrelated company in return for prepaid lease payments in the total amount of

$83.0

million (the “Deferred Lease Income”). The carrying value of the leased assets as of

December

31,

2016

and

2015

amounted to

$28.0

million and

$30.7

million, net of accumulated depreciation of

$32.9

million and

$30.2

million, respectively. The unrelated company (the “Lessor”) simultaneously leased back the Puna Power Plant to PGV under a

23

-year lease (the “Project Lease”). PGV’s rent obligations under the Project Lease will be paid solely from revenues generated by the Puna Power Plant under a PPA that PGV has with Hawaii Electric Light Company (“HELCO”). The Head Lease and the Project Lease are non-recourse lease obligations to the Company. PGV’s rights in the geothermal resource and the related PPA have not been leased to the Lessor as part of the Head Lease but are part of the Lessor’s security package.

The Head Lease and the Project Lease are being accounted for separately. Each was classified as an operating lease in accordance with the accounting standards for leases. The Deferred Lease Income is amortized into revenue, using the straight-line method, over the

31

-year term of the Head Lease. Deferred transaction costs amounting to

$4.2

million are being amortized, using the straight-line method, over the

23

-year term of the Project Lease.

Future minimum lease payments under the Project Lease, as of

December

31,

2016,

are as follows:

	(Dollars in thousands)
Year ending December 31:
2017	$	8,747
2018		8,944
2019		6,018
2020		2,450
2021		1,723
Thereafter		2,740
Total	$	30,622

Depository accounts

As required under the terms of the lease agreements, there are certain reserve funds that need to be managed by the indenture trustee in accordance with certain balance requirements. Such reserve funds amounted to

$2.9

million and

$2.1

million as of

December

31,

2016

and

2015,

respectively, and were included in restricted cash accounts in the consolidated balance sheets and were classified as current as they were used for current payments

.

Distribution account

PGV maintains an account to deposit its remaining cash, after making all of the necessary payments and transfers as provided for in the lease agreements, in order to make distributions to Ormat Nevada. The distributions are allowed only if PGV maintains various restrictive covenants under the lease agreements, which include limitations on additional indebtedness. As of

December

31,

2016

and

2015,

the balance of such account was

$0

.

XML

Note 14 - Tax Monetization Transactions

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Disclosure Of Investments In And Advances To Affiliates [Text Block]

NOTE

14

—TAX MONETIZATION TRANSACTIONS

OPAL

TRANSACTION

On

December

16,

2016,

the Company’s wholly owned subsidiary Ormat Nevada Inc. (“Ormat Nevada”) entered into an equity contribution agreement (the “Equity Contribution Agreement”) with OrLeaf LLC (“OrLeaf”) and JPM Capital Corporation (“JPM”) with respect to Opal Geo LLC (“Opal Geo”). Also on

December

16,

2016,

OrLeaf, a newly formed limited liability company formed by Ormat Nevada and ORPD LLC, entered into an amended and restated limited liability company agreement of Opal Geo (the “LLC Agreement”) with JPM. The transactions contemplated by the Equity Contribution Agreement and LLC Agreement will allow the Company to monetize federal production tax credits (“PTCs”) and certain other tax benefits relating to the operation of

five

geothermal power plants located in Nevada.

In connection with the

transactions contemplated by the Equity Contribution Agreement and the LLC Agreement, Ormat Nevada transferred its indirect ownership interest in the McGinness Hills (Phase I and Phase II), Tuscarora, Jersey Valley and Don A. Campbell Phase

2

(“DAC

2”)

geothermal power plants to Opal Geo. Prior to such transfer, Ormat Nevada held an approximately

63

.25%

indirect ownership interest in DAC

2

through ORPD LLC, a joint venture between Ormat Nevada and Northleaf Geothermal Holdings LLC (“Northleaf”), an affiliate of Northleaf Capital Partners, and held, directly or indirectly, a

10

0%

ownership interest in the remaining geothermal power plants that were transferred to Opal Geo.

Pursuant

to the Equity Contribution Agreement, JPM contributed approximately

$62.1

million to Opal Geo in exchange for

100%

of the Class B Membership Interests of Opal Geo. JPM also agreed to make deferred capital contributions to Opal Geo based on the amount of electricity generated by the DAC

2

and McGinness Hills Phase II power plants which are eligible for the federal production tax credit. The Company expects the aggregate amount of JPM’s deferred capital contributions to equal approximately

$21

million and to be paid over time covering the period through

December

31,

2022.

Und

er the LLC Agreement, until

December

31,

2022,

OrLeaf will receive distributions of

97.5%

of any distributable cash generated by operation of the power plants while JPM will receive distributions of

2.5%

of any distributable cash generated by operation of the power plants. Unless JPM has already achieved its target internal rate of return on its investment in Opal Geo, from

December

31,

2022

until JPM has achieved its target internal rate of return, JPM will receive

10

0%

of any distributable cash generated by operation of the power plants. Thereafter, OrLeaf will receive distributions of

97.5%,

and JPM will receive

2.5%,

of any distributable cash generated by operation of the power plants.

Und

er the LLC Agreement, all items of Opal Geo income and loss

, gain, deduction and credit (including the federal production tax credits relating to the operation of the

two

PTC eligible power plants) will be allocated, until JPM has achieved its target internal rate of return on its investment in Opal Geo (and for so long as the

two

PTC eligible power plants are generating PTCs),

99%

to JPM and

1%

to OrLeaf, or

5%

to JPM and

95%

to OrLeaf if PTCs are no longer available to either of the

two

PTC eligible power plants. Once JPM achieves its target internal rate of return, all items of Opal Geo income and loss, gain, deduction and credit will be allocated

5%

to JPM and

95%

to OrLeaf.

Und

er the LLC Agreement, OrLeaf, which owns

1

00%

of the Class A Membership Interests in Opal Geo, will serve as the managing member of Opal Geo and control the day-to

-day management of Opal Geo and its portfolio of

five

power plants. However, in certain limited circumstances (such as bankruptcy of Orleaf, fraud or gross negligence by OrLeaf) JPM

may

remove OrLeaf as the managing member of Opal Geo. JPM, as the Class B Member of Opal Geo, has consent and approval rights with respect to certain items that are designated as major decisions for Opal Geo and the

five

power plants. In addition, by virtue of certain provisions in OrLeaf’s own limited liability company agreement, and consistent with the ORPD LLC formation documents, Northleaf has similar consent and approval rights with respect to OrLeaf’s determination of major decisions pertaining to the DAC

2

power plant

. In both cases, these major decisions are generally equivalent to customary minority protection rights. As a result, the Company’s wholly owned subsidiary

, Ormat Nevada, which serves as the managing member of OrLeaf and as the managing member of ORPD LLC

, will effectively retain the day-to-day control and management of Opal Geo and its portfolio of

five

power plants.

The

LLC Agreement contains certain customary restrictions on transfer applicable to both OrLeaf and JPM with respect to their respective Membership Interests in Opal Geo, and also provides OrLeaf with a right of

first

offer in the event JPM desires to transfer any of its Class B Membership Interests, pursuant to which OrLeaf

may

purchase such Class B Membership Interests. The LLC Agreement also provides OrLeaf with the option to purchase all of the Class B Membership Interests on either

December

31,

2022

or the date that is

9

years after the closing date under the Equity Contribution Agreement at a price equal to the greater of (i) the fair market value of the Class B Membership Interests as of the date of purchase (subject to certain adjustments) and (ii)

$3

million.

Pursuant

to the Equity Contribution Agreement, the Company has provided a guaranty for the benefit of JPM of certain of OrLeaf’s indemnification obligations to JPM under the LLC Agreement. In addition, Ormat Nevada also provided a guaranty for the benefit of JPM of all present and future payment and performance obligations of OrLeaf under the LLC Agreement and each ancillary document to which OrLeaf is a party.

Pursuant to the Equity Contribution Agreement, JPM contributed approximately

$62.1

million to Opal Geo in exchange for

100%

of the Class B Membership Interests of Opal Geo. The contribution was recorded as

$3.7

million allocation to noncontrolling interests and

$58.5

million allocation to liability associated with sale of tax benefits

as described in Note

1.

JPM also agreed to make deferred capital contributions to Opal Geo based on the amount of electricity generated by the DAC

2

and McGinness Hills Phase II power plants which are eligible for the federal production tax credit. 

OPC TRANSACTION

In

June

2007,

Ormat Nevada entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. (Morgan Stanley Geothermal LLC and Lehman-OPC LLC), under which those investors purchased, for cash, interests in a newly formed subsidiary of Ormat Nevada, OPC LLC (“OPC”), entitling the investors to certain tax benefits (such as production tax credits (“PTCs”) and accelerated depreciation) and distributable cash associated with

four

geothermal power plants

.

The

first

closing under the agreements occurred in

2007

and covered the Company

’s Desert Peak

2,

Steamboat Hills, and Galena

2

power plants. The investors paid

$71.8

million at the

first

closing. The

second

closing under the agreements occurred in

2008

and covered the Galena

3

power plant. The investors paid

$63.0

million at the

second

closing.

Ormat Nevada continues to operate and maintain the power plants. Under the agreements, Ormat Nevada initially received all of the distributable cash flow generated by the power plants, while the investors received substantially all of the production tax credits and taxable income or loss (together, the “Economic Benefits”). Once Ormat Nevada recovered the capital that it has invested in the power plants, which occurred in the

fourth

quarter of

2010,

the investors receive both the distributable cash flow and the Economic Benefits. The investors

’ return is limited by the term of the transaction. Once the investors reach a target after-tax yield on their investment in OPC (the “OPC Flip Date”), Ormat Nevada will receive

95%

of both distributable cash and taxable income, on a going forward basis. Following the OPC Flip Date, Ormat Nevada also has the option to buy out the investors’ remaining interest in OPC at the then-current fair market value or, if greater, the investors’ capital account balances in OPC. Should Ormat Nevada exercise this purchase option, it would thereupon revert to being sole owner of the power plants.

The Class B membership units are provided with a

5%

residual economic interest in OPC. The

5%

residual interest commences on achievement by the investors of a contractually stipulated return that triggers the OPC Flip Date. The actual OPC Flip Date is expected to occur in the

second

quarter of

2017.

This residual

5%

interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments. Cash is distributed each period in accordance with the cash allocation percentages stipulated in the agreements. Until the

fourth

quarter of

2010,

Ormat Nevada was allocated the cash earnings in OPC and therefore, the amount allocated to the

5%

residual interest represented the noncash loss of OPC which principally represented depreciation on the property, plant and equipment. As from the

fourth

quarter of

2010,

the distributable cash is allocated to the Class B membership units.

As a result of the acquisition by Ormat Nevada, on

October

30,

2009,

of all of the Class B membership units of OPC held by Lehman-OPC LLC (see below), the residual interest decreased to

3.5%.

Such residual interest increased to

5%

on

February

3,

2011

when Ormat Nevada sold its Class B membership units to JPM Capital Corporation (“JPM”) (see below).

The Company

’s voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. Through Ormat Nevada, the Company owns all of the Class A membership units, which represent

75%

of the voting rights in OPC. The investors own all of the Class B membership units, which represent

25%

of the voting rights in OPC. In the period from

October

30,

2009

to

February

3,

2011,

the Company owned, through Ormat Nevada, all of the Class A membership units, which represented

75%

of the voting rights in OPC, and

30%

of the Class B membership units, which represented

7.5%

of the voting rights of OPC. In total the Company had

82.5%

of the voting rights in OPC as of

December

31,

2010.

In that period, the investors owned

70%

of the Class B membership units, which represented

17.5%

of the voting rights of OPC. Other than in respect of customary protective rights, all operational decisions in OPC are decided by the vote of a majority of the membership units. Following the OPC Flip Date, Ormat Nevada’s voting rights will increase to

95%

and the investor’s voting rights will decrease to

5%.

Ormat Nevada retains the controlling voting interest in OPC both before and after the OPC Flip Date and therefore consolidates OPC.

On

October

30,

2009,

Ormat Nevada acquired from Lehman-OPC

LLC all of the Class B membership units of OPC held by Lehman-OPC pursuant to a right of

first

offer for a price of

$18.5

million. A substantial portion of the initial sale of the Class B membership units by Ormat Nevada was accounted for as a financing transaction. As a result, the repurchase of these interests at a discount resulted in a pre-tax gain of

$13.3

million in the year ended

December

31,

2009.

In addition, an amount of approximately

$1.1

million has been reclassified from noncontrolling interest to additional paid-in capital representing the

1.5%

residual interest of Lehman-OPC’s Class B membership units.

On

February

3,

2011,

Ormat Nevada sold to JPM all of the Class B membership units of OPC that it had acquired on

October

30,

2010

for a sale price of

$24.9

million in cash. The Company did not record any gain from the sale of its Class B membership interests in OPC to JPM

.

A substantial portion of the Class B membership units are accounted for as a financing transaction. As a result, the majority of these proceeds were recorded as a liability. In addition,

$2.3

million has been reclassified from additional paid-in capital to noncontrolling interest representing the

1.5%

residual interest of JPM’s Class B membership units.

O

RTP

TRANSACTION

In

January

 

2013,

Ormat Nevada entered into agreements with JP Morgan (“JPM”) under which JPM purchased interests in a newly formed subsidiary of Ormat Nevada, ORTP, LLC (“ORTP”), entitling JPM to certain tax benefits (such as PTCs and accelerated depreciation) associated with certain geothermal power plants in California and Nevada.

Under the terms of the transaction, Ormat Nevada transferred the Heber complex, the Mammoth complex, the Ormesa complex, and the Steamboat

2

and

3,

Burdette (Galena

1)

and Brady power plants to ORTP, and sold class

 B membership units in ORTP to JPM. In connection with the closing, JPM paid approximately

$35.7

million to Ormat Nevada and will make additional payments to Ormat Nevada of

25%

of the value of PTCs generated by the portfolio over time. The additional payments were expected to be made until

December

 

31,

2016

up to maximum amount of

$11.0

million. In the

first

quarter of

2017

and

2016,

the Company received

$1.6

million and

$2.0

million, respectively.

Ormat Nevada will continue to operate and maintain the power plants. Under the agreements, Ormat Nevada will initially receive all of the distributable cash flow generated by the power plants, while JPM will receive substantially all of PTCs and the taxable income or loss (together, the “Economic Benefits”). JPM

’s return is limited by the terms of the transaction. Once JPM reaches a target after-tax yield on its investment in ORTP (the “ORTP Flip Date”), Ormat Nevada will receive

97.5%

of the distributable cash and

95%

of the taxable income, on a going forward basis. At any time during the

twelve

-month period after the end of the fiscal year in which the ORTP Flip Date occurs (but no earlier than the expiration of

five

years following the date that the last of the power plants was placed in service for purposes of federal income taxes), Ormat Nevada also has the option to buy out JPM’s remaining interest in ORTP at the then-current fair market value. If Ormat Nevada were to exercise this purchase option, it would become the sole owner of the power plants again.

The Class B membership units entitle the holder to

5.0%

(allocation of income and loss) and

2.5%

(allocation of cash) residual economic interests in ORTP. The

5.0%

and

2.5%

residual interests commence on achievement by JPM of a contractually stipulated return that triggers the ORTP Flip Date. The actual ORTP Flip Date is expected to occur in the

second

quarter of

2017.

These residual

5.0%

and

2.5%

interests represent noncontrolling interests and are not subject to mandatory redemption or guaranteed payments.

The Company

’s voting rights in ORTP are based on a capital structure that is comprised of Class A and Class B membership units. Through Ormat Nevada the Company owns all of the Class A membership units, which represent

75%

of the voting rights in ORTP. JPM owns all of the Class B membership units, which represent

25%

of the voting rights of ORTP. Other than in respect of customary protective rights, all operational decisions in ORTP are decided by the vote of a majority of the membership units. Ormat Nevada retains the controlling voting interest in ORTP both before and after the ORTP Flip Date and therefore will continue to consolidate ORTP.

XML

Note 15 - Asset Retirement Obligation

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Asset Retirement Obligation Disclosure [Text Block]

NOTE

15

 — ASSET RETIREMENT OBLIGATION

The following table presents a reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligation for the years presented below:

	Year Ended December 31,
	2016		2015
	(Dollars in thousands)
Balance at beginning of year	$	20,856	$	19,142
Revision in estimated cash flows		303		(681	)
Liabilities incurred		540		859
Accretion expense		1,649		1,536
Balance at end of year	$	23,348	$	20,856

XML

Note 16 - Stock-based Compensation

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

NOTE

16

— STOCK-BASED COMPENSATION

The Company makes an estimate of expected forfeitures and recognizes compensation costs only for those stock-based awards expected to vest. As of

December

31,

2016,

the total future compensation cost related to unvested stock-based awards that are expected to vest is $

11.3

million, which will be recognized over a weighted average period of

1.4

years.

During the years ended

December

31,

2016,

2015

and

2014,

the Company recorded compensation related to stock-based awards as follows

:

	Year Ended December 31,
	2016		2015		2014
	(Dollars in thousands, except per share data)
Cost of revenues	$	2,400	$	1,753	$	3,076
Selling and marketing expenses		247		123		261
General and administrative expenses		2,510		2,079		2,234
Total stock-based compensation expense		5,157		3,955		5,571
Tax effect on stock-based compensation expense		617		440		836
Net effect of stock-based compensation expense	$	4,540	$	3,515	$	4,735

During the

fourth

quarters of

2016,

2015

and

2014,

the Company evaluated the trends in the stock-based award forfeiture rate and determined that the actual rates are

10.3%,

9.66%

and

8.02%,

respectively. This represents an increase of

7%,

20%

and

12%,

respectively, from prior estimates. As a result of the change in the estimated forfeiture rate, there was an immaterial impact on stock-based compensation expense in the respective periods.

Valuation assumptions

Prior to

2016,

t

he fair value of each grant of stock-based awards was estimated using the Black-Scholes valuation model and the assumptions noted in the following table. The Company’s expected term represented the period that the Company’s stock-based awards were expected to be outstanding. In the absence of enough historical information, the expected term was determined using the simplified method giving consideration to the contractual term and vesting schedule. In

2016,

The Company estimated the fair value of the stock-based awards using the Excercise Multiple-Based Lattice Model as it enables a degree of accounting for the complexities of option valuation and reduces the probability of a measurement error.

 The dividend yield forecast is expected to be

20%

of the Company’s yearly net profit, which is equivalent to a

1.1%

yearly weighted average dividend rate in the year ended

December

31,

2016.

The risk-free interest rate was based on the yield from U.S. constant treasury maturities bonds with an equivalent term. The forfeiture rate is based on trends in actual stock-based awards forfeitures.

The Company calculated the fair value of each stock-based award on the date of grant based on the following assumptions

:

	Year Ended December 31,
	2016			2015			2014
For stock options issued by the Company:
Risk-free interest rates		1.3	%		1.4	%		1.7	%
Expected lives (in years)		4.5			4.0			5.1
Dividend yield		1.1	%		0.7	%		0.9	%
Expected volatility		30.7	%		29.2	%		35.1	%
Forfeiture rate (weighted average)		8.4	%		0	%		0	%

Stock-based awards

The

2004

Incentive Compensation Plan

In

2004,

the Company

’s Board of Directors adopted the

2004

Incentive Compensation Plan

(“2004

Incentive Plan”), which provides for the grant of the following types of awards: incentive stock options, non-qualified stock options, restricted stock, stock appreciation rights (“SARs”), stock units, performance awards, phantom stock, incentive bonuses, and other possible related dividend equivalents to employees of the Company, directors and independent contractors. Under the

2004

Incentive Plan, a total of

3,750,000

shares of the Company’s common stock have been reserved for issuance, all of which could be issued as options or as other forms of awards. Options and SARs granted to employees under the

2004

Incentive Plan cliff vest and are exercisable from the grant date as follows:

25%

after

24

months,

25%

after

36

months, and the remaining

50%

after

48

months. Options granted to non-employee directors under the

2004

Incentive Plan cliff vest and are exercisable

one

year after the grant date. Vested shares

may

be exercised for up to

ten

years from the date of grant. The shares of common stock will be issued upon exercise of options or SARs from the Company’s authorized share capital. The

2004

Incentive Plan expired in

May

2012

upon adoption of the

2012

Incentive Plan, except as to share based awards outstanding on that date.

The

2012

Incentive Compensation Plan

In

May

2012,

the Company

’s shareholders adopted the

2012

Incentive Compensation Plan

(“2012

Incentive Plan”), which provides for the grant of the following types of awards: incentive stock options, non-qualified stock options, restricted stock, SARs, stock units, performance awards, phantom stock, incentive bonuses, and other possible related dividend equivalents to employees of the Company, directors and independent contractors. Under the

2012

Incentive Plan, a total of

4,000,000

shares of the Company’s common stock have been reserved for issuance, all of which could be issued as options or as other forms of awards. Options and SARs granted to employees under the

2012

Incentive Plan will vest and become exercisable as follows:

25%

vest

24

months after the grant date, an additional

25%

vest

36

months after the grant date, and the remaining

50%

vest

48

months after the grant date. Options granted to non-employee directors under the

2012

Incentive Plan will vest and become exercisable

one

year after the grant date. Vested stock-based awards

may

be exercised for up to

ten

years from the date of grant. The shares of common stock will be issued upon exercise of options or SARs from the Company’s authorized share capital.

The

2012

Incentive Plan empowers our Board of Directors, in its discretion, to amend the

2012

Incentive Plan in certain respects. Consistent with its authority to amend the Incentive Plan, in

February

2014

the Board adopted and approved certain amendments to the

2012

Incentive Plan. The key amendments are as follows:

Increase of per grant limit: Section

15(a)

of the

2012

Incentive Plan was amended to allow the grant of up to

400,000

shares of our common stock with respect to the initial grant of an equity award to newly hired executive officers in any calendar year. This amendment was adopted by our stockholders on

May

31,

2014;

and

Acceleration of vesting: Section

15(l)

of the

2012

Incentive Plan was amended to clarify our ability to provide in the applicable award agreement that part and/or all of the award will be accelerated upon the occurrence of certain pre-determined events and/or conditions, such as a "change in control" (as defined in the

2012

Incentive Plan, as amended).

On

February

11,

2014,

the Company granted its Chief Financial Officer options to purchase

32,500

shares of common stock

under the

2012

Incentive Plan. The exercise price of each option is

$24.57,

which represented the fair market value of the Company’s common stock on the grant date. Such options will expire

five

years from the date of grant and will vest in equal annual installments over a period of

three

years from the grant date, subject to acceleration upon a change of control.

The fair value of each stock option on the grant date was

$5.78.

The Company calculated the fair value of each stock option on the date of grant using the Black-Scholes valuation model based on the following assumptions:

Risk-free interest rates	0.81	%
Expected life (in years)	3.375
Dividend yield	0.80	%
Expected volatility	33.50	%
Forfeiture rate	0.00	%

On

April

2,

2014,

the Company granted its newly appointed Chief Executive Officer options to purchase up to an aggregate of

400,000

shares of common stock under the

2012

Incentive Plan. The exercise price of each option is

$29.52

per share, which represented the fair market value of the Company

’s common stock on the date of the grant. Options to purchase

300,000

shares of common stock will expire

six

years following the date of grant and will vest in equal annual installments over

four

years from the grant date, subject to acceleration in the event of a change of control. The remaining options to purchase

100,000

shares of common stock will vest on

March

31,

2021,

subject to acceleration associated with a change of control, and will expire

seven

and a half years from the date of grant.

The fair value of each option on the grant date was

$12.88

for grant of options to purchase

300,000

shares of common stock, and

$8.33

for the grant of options to purchase

100,000

shares of common stock. The Company calculated the fair value of each stock option on the date of grant using the Black-Scholes valuation model based on the following assumptions:

	Grant of options to purchase 300,000 shares of common stock			Grant of options to purchase 100,000 shares of common stock
Risk-free interest rates		2.36	%		1.64	%
Expected life (in years)		7.25			4.75
Dividend yield		0.90	%		0.90	%
Expected volatility		42.80	%		33.10	%

On

November

5,

2014,

the Company granted its directors options to purchase

52,500

shares of common stock under the

2012

Incentive Plan. The exercise price of each option is

$28.23,

which represented the fair market value of the Company

’s common stock on the grant date. Such options will expire

seven

years from the date of grant and will fully vest

one

year from the grant date.

The fair value of each stock option on the grant date was

$7.01.

The Company calculated the fair value of each stock option on the date of grant using the Black-Scholes valuation model based on the following assumptions:

Risk-free interest rates	1.30	%
Expected life (in years)	4.0
Dividend yield	0.70	%
Expected volatility	32.40	%
Forfeiture rate	0.00	%

On

November

3,

2015,

the Company granted its directors options to purchase

45,000

shares of common stock under the

2012

Incentive Plan. The exercise price of each option is

$38.24,

which represented the fair market value of the Company

’s common stock on the grant date. Such options will expire

seven

years from the date of grant and will fully vest

one

year from the grant date.

The fair value of each stock option on the grant date was

$8.68.

The Company calculated the fair value of each stock option on the date of grant using the Black-Scholes valuation model based on the following assumptions:

Risk-free interest rates	1.35	%
Expected life (in years)	4.0
Dividend yield	0.70	%
Expected volatility	29.20	%
Forfeiture rate	0.00	%

On

June

13,

2016,

the Company granted its employees, in aggregated

1,080,000

SAR under the Company

’s

2012

Incentive Plan. The exercise price of each SAR is

$42.87,

which represented the fair market value of the Company’s common stock on the grant date. Such SARs will expire

six

years from the date of the grant and will vest over

4

years as follows:

50%

after

two

years; an additional

25%

after

three

years and the remaining

25%

after

four

years from the grant date.

The fair value of each SAR on the grant date was

$11.98

for senior management and

$11.42

for other employees. The Company calculated the fair value of each SAR on the grant date using the Exercise Multiple-Based Lattice SAR-Pricing model based on the following assumptions:

Risk-free interest rate	1.29	%
Expected life (in years)	6
Dividend yield	1.14
Expected volatility	30.7	%
Forfeiture rate:
Senior management	0.0	%
Other employees	10.5	%
Sub-Optimal Exercise Factor:
Senior management	2.5
Other employees	2.0

On

November

8,

2016,

the Company granted its directors, in aggregated

60,000

SAR

’s under the Company’s

2012

Incentive Plan. The exercise price of each SAR is

$47.46,

which represented the fair market value of the Company’s common stock on the grant date. Such SARs will expire

seven

years from the date of the grant and will vest at the end of the

first

year from the grant date.

The fair value of each SAR on the grant date was

$14.51.

The Company calculated the fair value of each SAR on the grant date using the Exercise Multiple-Based Lattice SAR-Pricing model based on the following assumptions:

Risk-free interest rate	1.65	%
Expected life (in years)	7
Dividend yield	1.1
Expected volatility	30.6	%
Forfeiture rate:	0.0	%
Sub-Optimal Exercise Factor:	2.5

	Year Ended December 31,
	2016					2015					2014
	Shares (in thousands)			Weighted Average Exercise Price		Shares (in thousands)			Weighted Average Exercise Price		Shares (in thousands)			Weighted Average Exercise Price
Outstanding at beginning of year		2,438		$	25.38		4,477		$	27.48		4,710		$	28.23
Granted, at fair value:
Stock Options		1,155			43.01		45			38.24		485			29.05
SARs*		—			—		—			—		—			—
Exercised		(967	)		25.33		(1,589	)		26.77		(243	)		24.10
Forfeited		(57	)		24.12		(125	)		27.33		(116	)		23.20
Expired		(4	)		26.84		(370	)		45.78		(359	)		42.70
Outstanding at end of year		2,565			33.36		2,438			25.38		4,477			27.48
Options and SARs exercisable at end of year		557			25.22		858			26.75		2,106			31.25
Weighted-average fair value of options and SARs granted during the year				$	11.61				$	8.68				$	9.00

__________

* Upon exercise, SARs entitle the recipient to receive shares of common stock equal to the increase in value of the award between the grant date and the exercise date.

As of

December

 

31,

2016,

1,058,150

 shares of the Company’s common stock are available for future grants under the

2012

Incentive Plan. No shares of the Company’s common stock are available for future grants under the

2004

Incentive Plan as of such date.

The following table summarizes information about stock-based awards outstanding at

December

 

31,

2016

(shares in thousands):

		Options Outstanding						Options Exercisable
Exercise Price		Number of Stock-based Awards Outstanding		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value		Number of Stock-based Awards Exercisable		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value
$	18.56		15		2.8	$	526		15		2.8	$	526
	19.69		15		2.6		509		15		2.6		509
	20.13		108		2.3		3,608		108		2.3		3,608
	20.54		53		2.3		1,761		28		2.3		934
	23.34		635		2.4		19,226		140		2.4		4,247
	24.57		9		2.1		269		1		2.1		33
	25.65		68		1.3		1,905		68		1.3		1,905
	26.70		15		3.8		404		15		3.8		404
	28.23		30		4.8		762		30		4.8		762
	29.52		400		3.6		9,640		75		3.6		1,807
	29.95		17		0.3		400		17		0.3		400
	35.15		15		6.1		277		-		-		-
	38.24		45		5.8		692		45		5.8		692
	42.87		1,080		5.5		11,610		-		-		-
	47.46		60		6.9		370		-		-		-
			2,565		4.1	$	51,959		557		2.7	$	15,827

The following table summarizes information about stock-based awards outstanding at

December

 

31,

2015

(shares in thousands):

		Options Outstanding						Options Exercisable
Exercise Price		Number of Stock-based Awards Outstanding		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value		Number of Stock-based Awards Exercisable		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value
$	18.56		15		3.8	$	269		15		3.8	$	269
	19.69		15		3.6		252		15		3.6		252
	20.13		326		3.3		5,327		69		3.3		1,135
	20.54		100		3.3		1,593		50		3.3		797
	23.34		938		3.4		12,315		126		3.4		1,655
	24.57		33		3.1		387		16		3.1		193
	25.65		135		2.3		1,462		135		2.3		1,462
	26.70		45		4.8		440		45		4.8		440
	26.84		64		0.2		618		64		0.2		618
	28.19		15		1.8		124		15		1.8		124
	28.23		45		5.8		371		45		5.8		371
	29.21		3		1.3		22		3		1.3		22
	29.52		400		4.6		2,780		-		-		-
	29.95		148		1.3		963		148		1.3		963
	34.13		96		0.3		225		96		0.3		225
	38.24		15		6.8		-		-		-		-
	38.50		15		0.8		-		15		0.8		-
			2,438		3.3	$	27,148		857		2.4	$	8,526

The aggregate intrinsic value in the above tables represents the total pretax intrinsic value, based on the Company

’s stock price of

$53.62

and

$36.47

as of

December

31,

2016

and

2015,

respectively, which would have potentially been received by the stock-based award holders had all stock-based award holders exercised their stock-based award as of those dates. The total number of in-the-money stock-based awards exercisable as of

December

31,

2016

and

2015

was

557,350

and

842,911,

respectively.

The total pretax intrinsic value of options exercised during the year ended

December

31,

2016

and

2015

was $

18.0

million and

$14.1

million, respectively, based on the average stock price of

$43.99

and

$35.64

during the years ended

December

31,

2016

and

2015,

respectively.

XML

Note 17 - Power Purchase Agreements

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Leases of Lessor Disclosure [Text Block]

NOTE

17

— POWER PURCHASE AGREEMENTS

Substantially all of the Company

’s electricity revenues are recognized pursuant to PPAs in the U.S. and in various foreign countries, including Kenya and Guatemala. These PPAs generally provide for the payment of energy payments or both energy and capacity payments through their respective terms which expire in varying periods from

2017

to

2036.

Generally, capacity payments are calculated based on the amount of time that the power plants are available to generate electricity. The energy payments are calculated based on the amount of electrical energy delivered at a designated delivery point. The price terms are customary in the industry and include, among others, a fixed price, short-run avoided cost (“SRAC”) (the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others), and a fixed price with an escalation clause that includes the value for environmental attributes, known as renewable energy credits. Certain of the PPAs provide for bonus payments in the event that the Company is able to exceed certain target levels and potential payments by the Company if it fails to meet minimum target levels. One PPA gives the power purchaser or its designee the right of

first

refusal to acquire the geothermal power plants at fair market value. Upon satisfaction of certain conditions specified in this PPA, and subject to receipt of requisite approvals and negotiations between the parties, the Company has the right to demand that the power purchaser acquire the power plant at fair market value. The Company’s subsidiaries in Guatemala sell power at an agreed upon price subject to terms of a “take or pay” PPA.

Pursuant to the terms of certain of the PPAs, the Company

may

be required to make payments to the relevant power purchaser under certain conditions, such as shortfall in delivery of renewable energy and energy credits, and not meeting certain performance threshold requirements, as defined in the relevant PPA. The amount of payment required is dependent upon the level of shortfall in delivery or performance requirements and is recorded in the period the shortfall occurs. In addition, if the Company does not meet certain minimum performance requirements, the capacity of the power plant

may

be permanently reduced

.

As discussed in Note

1,

the Company assessed all PPAs agreed to, modified or acquired in business combinations on or after

July

1,

2003,

and evaluated whether such PPAs contained a lease element requiring lease accounting. Future lease revenues under PPAs which contain a lease element as of

December

31,

2016

including the PPAs that provide for minimum production or performance guarantees are accounted for as contingent lease revenues as they are production-based payments and contingent on generation levels that are impacted by climatic variables that are inherently uncertain including geological conditions and ambient temperature.

The PPAs considered to be leases were also assessed for inclusion of embedded derivatives, which required that they be separately accounted for at fair value. However, none of such PPAs were determined to include embedded derivatives.

XML

Note 18 - Interest Expense, Net

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Interest Expense Disclosure [Text Block]

NOTE

18

 — INTEREST EXPENSE, NET

The components of interest expense are as follows:

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Interest related to sale of tax benefits	$	9,349		$	9,620		$	12,413
Interest expense		61,327			67,032			75,447
Less — amount capitalized		(3,287	)		(4,075	)		(3,206	)
	$	67,389		$	72,577		$	84,654

XML

Note 19 - Income Taxes

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Income Tax Disclosure [Text Block]

NOTE

 

19

 — INCOME TAXES

U.S. and foreign components of income (loss) from continuing operations, before income taxes and equity in income (losses) of investees consisted of:

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
U.S	$	(7,109	)	$	(236	)	$	(2,623	)
Non-U.S. (foreign)		148,197			113,835			88,459
	$	141,088		$	113,599		$	85,836

The components of the provision (benefit) for income taxes, net are as follows:

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Current:
Federal	$	—		$	51		$	—
State		(276	)		252			490
Foreign		14,040			19,175			13,983
	$	13,764		$	19,478		$	14,473
Deferred:
Foreign		18,073			(34,736	)		13,135
		18,073			(34,736	)		13,135
	$	31,837		$	(15,258	)	$	27,608

The significant components of the deferred income tax expense (benefit) are as follows:

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Other deferred tax expense (exclusive of the effect of other components listed below)	$	(1,105	)	$	541		$	(18,424	)
Usage (benefit) of operating loss carryforwards - U.S.		(14,072	)		(30,596	)		7,764
Change in valuation allowance		16,411			(14,324	)		3,526
Change in foreign valuation allowance		—			(49,701	)		—
Change in foreign income tax		18,073			14,965			13,135
Change in lease transaction		—			(452	)		2,136
Change in tax monetization transaction		48,000			16,386			5,184
Change in depreciation		(55,462	)		28,370			9,431
Change in intangible drilling costs		10,227			10,335			(9,706	)
Change in production tax credits and alternative minimum tax credit		(11,659	)		610			89
Basis difference in partnership interests		7,660			(10,870	)		—
	$	18,073		$	(34,736	)	$	13,135

Reconciliation of the U.S.

 federal statutory tax rate to the Company’s effective income tax rate is as follows:

	Year Ended December 31,
	2016			2015			2014
U.S. federal statutory tax rate		35.0	%		35.0	%		35.0	%
Valuation allowance - U.S.		11.1			(1.4	)		(1.7	)
Valuation allowance - foreign		-			(43.8	)
Tax monetization		-			-			2.5
State income tax, net of federal benefit		(0.2	)		0.6			(0.7	)
Effect of foreign income tax, net		(14.1	)		(5.1	)		(4.9	)
Production tax credits		(8.3	)		(0.1	)		0.9
Subpart F income		0.3			1.3			1.4
Depletion		-			-			(1.1	)
Other, net		(1.3	)		-			0.8
Effective tax rate		22.5	%		(13.5)	%		32.2	%

The net deferred tax assets and liabilities consist of the following:

	December 31,
	2016			2015
	(Dollars in thousands)
Deferred tax assets (liabilities):
Net foreign deferred taxes, primarily depreciation	$	(35,382	)	$	(32,654	)
Depreciation		148,419			87,943
Intangible drilling costs		(112,762	)		(102,013	)
Net capital loss carryforward - U.S.		117,924			103,850
Tax monetization transaction		(105,789	)		(80,478	)
Investment tax credits		1,341			1,341
Production tax credits		82,451			70,792
Stock options amortization		3,241			3,467
Basis difference in partnership interest		(24,462	)		(16,801	)
Accrued liabilities and other		(752	)		2,435
		74,229			37,882
Less - valuation allowance		(109,611	)		(70,536	)
Total	$	(35,382	)	$	(32,654	)

The following table presents a reconciliation of the beginning and ending valuation allowance:

	Year Ended December 31,
	2016		2015			2014
	(Dollars in thousands)
Balance at beginning of the year	$	70,536	$	111,280		$	114,806
Additions to (release of) valuation allowance		39,075		(40,744	)		(3,526	)
Balance at end of the year	$	109,611	$	70,536		$	111,280

At

December

31,

2016,

the Company had U.S. federal net operating loss (“NOL”) carryforwards of approximately

$2

99.6

million and state NOL carryforwards of approximately

$244.7

million, available to reduce future taxable income, which expire between

2029

and

2036

for federal NOLs and between

2018

and

2036

for state NOLs. The investment tax credits (“ITCs”) in the amount of

$1.3

million at

December

31,

2016

are available for a

20

-year period and expire between

2022

and

2024.

The Production Tax Credits (“PTCs”) in the amount of

$82.5

million at

December

31,

2016

are available for a

20

-year period and expire between

2026

and

2036.

Realization of the deferred tax assets and tax credits is dependent on generating sufficient taxable income in appropriate jurisdictions prior to expiration of the NOL carryforwards and tax credits.

Based upon available evidence of the Company’s ability to generate additional taxable income in the future and historical losses in prior years, a valuation allowance in the amount of

$109.6

 million and

$70.5

million is recorded against the U.S. deferred tax assets as of

December

31,

2016

and

2015,

respectively, as it is more likely than not that the deferred tax assets will not be realized. 

The increase in valuation allowance is due to increases in investment tax credits and step-up in basis relating to the tax monetization transaction.

As more fully described in Note

3,

On

November

23,

2016,

the Company closed a follow-on sale of

36.75%

of equity interest in the

second

phase of the Don A. Campbell power plant, as a result of this sale, the Company will recognize

$21.4

million of taxable income in

2016.

Following the closing, DACII was contributed to the existing ORPD, as agreed upon under the ORPD agreement with Northleaf.

On

December

16,

2016,

upon the formation of Opal and Orleaf, Orleaf

distributed

$43.1

million to Ormat and

$19

million to ORPD. Upon this distribution, Ormat will

recognize

taxable gain of

$4.8

million.

In

November

2015,

the FASB issued Accounting Standards Update

2015

-

17,

Balance Sheet Classification of Deferred Taxes (ASU

2015

-

17),

effective in fiscal years beginning after

December

15,

2016.

The new guidance requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The Company has elected early adoption of the aforementioned Update in

2015.

The Company has adopted the Update prospectively. As such, the deferred tax assets and liabilities in

2016

and

2015

are being presented as noncurrent on the balance sheet.

In

March

2016,

the FASB issued Accounting Standards Update

2016

-

09,

Improvements to Employee Share-Based Payment Accounting (ASU

2016

-

09),

effective in fiscal years beginning after

December

15,

2016

for public companies. In general, the new guidance

allows entities to record all excess tax benefits and tax deficiencies as income tax benefit or expense in the income statement. The Company has not elected an early adoption of the aforementioned Update.

In

October

2016,

the FASB issued Accounting Standards Update

2016

-

16,

Income Taxes on Intercompany Transfers (ASU

2016

-

16),

effective in fiscal years beginning after

December

15,

2017

for public companies. In general, the ne

w guidance provides that the seller and buyer will immediately recognize the current and deferred income tax consequences of the intercompany asset transfer. The Company has not elected an early adoption of the aforementioned Update.

The following table presents the deferred taxes on the balance sheets as of the dates indicated:

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Current deferred tax assets	$	—		$	—		$	251
Current deferred tax liabilities		—			—			(975	)
Non-current deferred tax liabilities		(35,382	)		(32,654	)		(66,219	)
	$	(35,382	)	$	(32,654	)	$	(66,943	)

The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $

367

million at

December

31,

2016.

It is the Company’s intention to reinvest undistributed earnings of its foreign subsidiaries and thereby indefinitely postpone their remittance. Accordingly, no provision has been made for foreign withholding taxes or U.S. income taxes which

may

become payable if undistributed earnings of foreign subsidiaries were paid as dividends to the Company. The additional taxes on that portion of undistributed earnings which is available for dividends are not practicably determinable.

The Company believes that based on our plans to increase the operations outside of the U.S., the cash generated from our operations outside of the U.S. will be reinvested outside of the U.S. and, accordingly, we do not currently plan to repatriate the funds we have designated as being permanently invested outside the U.S. If we change our plans, we

may

be required to accrue and pay U.S. taxes to repatriate these funds.

Uncertain tax positions

We are subject to income taxes in the U.S. (federal and state) and numerous foreign jurisdictions. Significant judgment is required in evaluating our tax positions and determining our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. We establish reserves for tax-related uncertainties based on estimates of whether, and the extent to which additional taxes will be due. These reserves are established when we believe that certain positions might be challenged despite our belief that our tax return positions are fully supportable. We adjust these reserves in light of changing facts and circumstances, such as the outcome of tax audits. The provision for income taxes includes the impact of reserve positions and changes to reserves that are considered probable.

At

December

31,

2016

and

2015,

there are

$5.7

million and

$10.4

million of unrecognized tax benefits that if recognized would affect the annual effective tax rate. Interest and penalties assessed by taxing authorities on an underpayment of income taxes are included as a component of income tax provision in the consolidated statements of operations and comprehensive income

.

A reconciliation of our unrecognized tax benefits is as follows:

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Balance at beginning of year	$	10,385		$	7,511		$	4,950
Additions based on tax positions taken in prior years		675			(198	)		230
Additions based on tax positions taken in the current year		1,059			4,386			2,980
Reduction based on tax positions taken in prior years		(6,381	)		(1,314	)		(649	)
Balance at end of year	$	5,738		$	10,385		$	7,511

The Company and its U.S. subsidiaries file consolidated income tax returns for federal and state purposes. As of

December

31,

2016,

the Company has not been subject to U.S. federal or state income tax examinations. The Company remains open to examination by the Internal Revenue Service for the years

2000

-

2016

and by local state jurisdictions for the years

2002

-

2016

.

These examinations

may

lead to ordinary course adjustments or proposed adjustments to our taxes or our net operating losses with respect to years under examination as well as subsequent periods.

The reduction of

$6.4

million,

$1.3

million and

$0.6

million in

2016,

2015

and

2014,

respectively, was due to the statute of limitations expiration on certain tax positions as well as Ormat System's tax settlement as detailed below. 

The Company

’s foreign subsidiaries remain open to examination by the local income tax authorities in the following countries for the years indicated:

Israel	2015	—	2016
Kenya	2001	—	2016
Guatemala	2010	—	2016
Philippines	2010	—	2016
New Zealand	2011	—	2016

Management believes that the liability for unrecognized tax benefits is adequate for all open tax years based on its assessment of many factors, including among others, past experience and interpretations of local income tax regulations. This assessment relies on estimates and assumptions and

may

involve a series of complex judgments about future events. As a result, it is possible that federal, state and foreign tax examinations will result in assessments in future periods. To the extent any such assessments occur, the Company will adjust its liability for unrecognized tax benefits

.

Tax benefits in the U.S

.

The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies under the ARRA which has been extended by the Consolidated Appropriations Act,

2016

(CAA) until

December

31,

2019.

The Company is permitted to claim

30%

of the eligible cost of each new geothermal power plant in the United States, which is placed in service before

January

1,

2017,

as an ITC against its federal income taxes. After this date, the ITC is reduced to

10%.

Alternatively, the Company is permitted to claim a PTC, which in

2016

is

2.3

cents per kWh and which

may

be adjusted annually for inflation. The PTC

may

be claimed for

ten

years on the electricity output of new geothermal power plants that have commenced construction by

December

31,

2016.

The owner of the power plant must choose between the PTC and the

30%

ITC described above. In either case, under current tax rules, any unused tax credit has a

1

-year carry back and a

20

-year carry forward. Whether the Company claims the PTC or the ITC, it is also permitted to depreciate most of the plant for tax purposes over

five

years on an accelerated basis, meaning that more of the cost

may

be deducted in the

first

few years than during the remainder of the depreciation period. If the Company claims the ITC, the Company

’s “tax base” in the plant that it can recover through depreciation must be reduced by half of the ITC. If the Company claims the PTC, there is no reduction in the tax basis for depreciation. Companies that place qualifying renewable energy facilities in service, during

2009,

2010

or

2011,

or that begin construction of qualifying renewable energy facilities during

2012,

2013,

2014

or

2015

and place them in service by

December

31,

2016,

may

choose to apply for a cash grant from the U.S. Department of the Treasury (“U.S. Treasury”) in an amount equal to the ITC. Likewise, the tax base for depreciation will be reduced by

50%

of the cash grant received. Under the ARRA revised by the CAA, the U.S. Treasury is instructed to pay the cash grant within

60

governmental business days of the application or the date on which the qualifying facility is placed in service.

Income taxes related to foreign operations

Guatemala

— The enacted tax rate is

25%.

Orzunil, a wholly owned subsidiary, was granted a benefit under a law which promotes development of renewable power sources. The law allows Orzunil to reduce the investment made in its geothermal power plant from income tax payable, which reduces the effective tax rate to

zero.

Ortitlan, another wholly owned subsidiary, was granted a tax exemption for a period of

ten

years ending

August

2017.

The effect of the tax exemption in the years ended

December

31,

2016,

2015,

and

2014

is

$3.3

million,

$3.6

million, and

$1.9

million, respectively

($0.07,

$0.08,

and

$0.04

per share of common stock, respectively).

Israel

— The Company’s operations in Israel through its wholly owned Israeli subsidiary, Ormat Systems Ltd. (“Ormat Systems”), are taxed at the regular corporate tax rate of

25%

in

2012,

25%

in

2013,

 

26.5%

in

2014

and

2015

and

25%

in

2016

and thereafter. Ormat Systems received “Benefited Enterprise” status under Israel’s Law for Encouragement of Capital Investments,

1959

(the “Investment Law”), with respect to

two

of its investment programs. As a Benefited Enterprise, Ormat Systems was exempt from Israeli income taxes with respect to income derived from the

first

benefited investment for a period of

two

years that started in

2004,

and thereafter such income was subject to reduced Israeli income tax rates which will not exceed

25%

for an additional

five

years until

2010.

Ormat Systems was also exempt from Israeli income taxes with respect to income derived from the

second

benefited investment for a period of

two

years that started in

2007,

and thereafter such income is subject to reduced Israeli income tax rates which will not exceed

25%

for an additional

five

years until

2013.

These benefits are subject to certain conditions, including among other things, that all transactions between Ormat Systems and its affiliates are at arm’s length, and that the management and control of Ormat Systems will be from Israel during the whole period of the tax benefits. A change in control should be reported to the Israel Tax Authority in order to maintain the tax benefits. In

January

2011,

new legislation amending the Investment Law was enacted. Under the new legislation, a uniform rate of corporate tax would apply to all qualified income of certain industrial companies, as opposed to the current law’s incentives that are limited to income from a “Benefited Enterprise” during their benefits period. According to the amendment, the uniform tax rate applicable to the zone where the production facilities of Ormat Systems are located would be

15%

in

2011

and

2012,

12.5%

in

2013,

and

16%

in

2014

and thereafter. Under the transitory provisions of the new legislation, Ormat Systems had the option either to irrevocably comply with the new law while waiving benefits provided under the previous law or to continue to comply with the previous law during a transition period with the option to move from the previous law to the new law at any stage.

Ormat Systems decided to irrevocably comply with the new law starting in

2011.

In

November

2012,

new legislation amending the Investment Law was enacted. Under the new legislation, companies that have retained earnings as of

December

31,

2011

from Benefited Enterprises

may

elect by

November

11,

2013

to pay a reduced corporate tax rate as set forth in the new legislation on such income and distribute a dividend from such income without being required to pay additional corporate tax with respect to such income.

  Ormat Systems decided not to make such election.

Ormat Systems tax assessment for fiscal years

2010

-

2014

was finalized and settled in

January

2017.

The settlement resulted in no impact to income statement due to release of the related uncertain tax position liability.

Kenya

- The Company’s operations in Kenya are taxed at the rate of

37.5%.

On

September

11,

2015,

Kenya's Income Tax Act was amended pursuant to certain provisions of the recently adopted Finance Act,

2015.

Among other matters, these amendments retain the enhanced investment deduction of

150%

under Section

17B

of the Income Tax Act, extend the period for deduction of tax losses from

5

years to

10

years under Sections

15(4)

and

15(5)

of the Income Tax Act, and amend the effective date from

January

1,

2016

to

January

1,

2015

under Sections

15(4)

and

15(5)

of the Income Tax Act. Previously, the Company had a valuation allowance for the additional

50%

investment deduction reducing its deferred tax asset in Kenya as the utilization of the related tax losses was not probable within the original

five

year carryforward period. As a result of the change in legislation and the expected continued profitability during the extended carryforward period, the Company expects that it will be able to fully utilize the carryforward tax losses within the

ten

year period and as such released the valuation allowance in Kenya resulting in a

$49.4

million of tax benefits in the year ended

December

31,

2015.

During the

fourth

quarter of

2016,

the Company determined that its income statement tax provision and deferred tax liabilities in Kenya in prior periods were overstated by approximately

$4.7

million as a result of errors in the determination of the exchange rate impact used in the calculation of taxable income at its Kenya operations. The Company recorded an adjustment to reduce income tax expense and deferred tax liabilities by

$4.7

million in the

fourth

quarter of

2016

to correct this matter. 

As previously reported by the Company, the Kenya Revenue Authority (“KRA”) conducted an audit related to the Company

’s operations in Kenya for fiscal years

2012

-

2013.

In

January

2017,

KRA concluded its audit for the subject period and issued a demand letter to the Company for additional tax payments of approximately

$16.1

million, including interest and penalties. KRA’s assessment, among other points, rejected the Company's income tax deduction of

150%

of its investment in geothermal well drilling during the relevant period, on the basis that such work falls under mining activities (and not geothermal activities) which have a different allowable deduction under the Kenya Income Tax Act. The KRA audit and assessment is not final and is subject to objection by the Company. The Company's operations in Kenya utilize a geothermal resource license from the Ministry of Energy and Petroleum. The Company does not conduct and is not involved in any mining activity under applicable Kenyan law. Therefore, the Company believes that its original tax position was and remains correct under Kenyan tax law and regulations, and has submitted a notice of objection to the KRA which it intends to pursue vigorously. If the KRA position prevails and is applied to subsequent periods, the Company's deferred tax asset of

$49.4

million recorded in

2015

may

be impacted. At present, the Company has recorded a provision based on its assessment of its reasonably expected potential exposure.

Other significant foreign countries

— The Company’s operations in New Zealand are taxed at the rate of

28%

in

2015,

2014

and

2013.

XML

Note 20 - Business Segments

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Segment Reporting Disclosure [Text Block]

NOTE

20

— BUSINESS SEGMENTS

The Company has

two

reporting segments: the Electricity and Product segments. These segments are managed and reported separately as each offers different products and serves different markets. The Electricity segment is engaged in the sale of electricity from the Company

’s power plants pursuant to PPAs. The Product segment is engaged in the manufacture, including design and development, of turbines and power units for the supply of electrical energy and in the associated construction of power plants utilizing the power units manufactured by the Company to supply energy from geothermal fields and other alternative energy sources. Transfer prices between the operating segments were determined on current market values or cost plus markup of the seller’s business segment.

Summarized financial information concerning the Company

’s reportable segments is shown in the following tables:

	Electricity		Product		Consolidated
	(Dollars in thousands)
Year Ended December 31, 2016:
Net revenues from external customers	$	436,292	$	226,299	$	662,591
Intersegment revenues		—		56,075		56,075
Depreciation and amortization expense		102,698		3,279		105,977
Operating income		126,828		75,054		201,882
Segment assets at period end		2,204,444		257,125		2,461,569
Expenditures for long-lived assets		147,211		4,719		151,930
Year Ended December 31, 2015:
Net revenues from external customers	$	375,920	$	218,724	$	594,644
Intersegment revenues		—		48,559		48,559
Depreciation and amortization expense		103,892		3,314		107,206
Operating income		99,345		64,716		164,061
Segment assets at period end		2,044,346		229,636		2,273,982
Expenditures for long-lived assets		149,666		2,784		152,450
Year Ended December 31, 2014 :
Net revenues from external customers	$	382,301	$	177,223	$	559,524
Intersegment revenues		—		44,718		44,718
Depreciation and amortization expense		97,826		2,973		100,799
Operating income		90,401		53,089		143,490
Segment assets at period end		1,963,486		158,070		2,121,556
Expenditures for long-lived assets		155,323		3,458		158,781

Reconciling information between reportable segments and the Company

’s consolidated totals is shown in the following table:

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Revenues:
Total segment revenues	$	662,591		$	594,644		$	559,524
Intersegment revenues		56,075			48,559			44,718
Elimination of intersegment revenues		(56,075	)		(48,559	)		(44,718	)
Total consolidated revenues	$	662,591		$	594,644		$	559,524
Operating income:
Operating income	$	201,882		$	164,061		$	143,490
Interest income		971			297			312
Interest expense, net		(67,389	)		(72,577	)		(84,654	)
Foreign currency translation and transaction losses		(5,534	)		(1,622	)		(5,839	)
Income attributable to sale of equity interest		16,503			25,431			24,143
Gain from sale of property, plant and equipment		—			—			7,628
Other non-operating income, net		(5,345	)		(1,991	)		756
Total consolidated income before income taxes and equity in income of investees	$	141,088		$	113,599		$	85,836

The Company sells electricity and products for power plants and others, mainly to the geographical areas according to location of the customers, as detailed below. The following tables present certain data by geographic area:

	Year Ended December 31,
	2016		2015		2014
	(Dollars in thousands)
Revenues from external customers attributable to: (1)
United States	$	307,025	$	286,509	$	293,710
Indonesia		100,856		93,191		38,174
Kenya		109,270		86,545		86,074
Turkey		46,270		57,356		86,340
Chile		58,032		34,478		—
Guatemala		30,086		27,897		28,439
Other foreign countries		11,052		8,668		26,787
Consolidated total	$	662,591	$	594,644	$	559,524

____________

(1)

Revenues as reported in the geographic area in which they originate.

	Year Ended December 31,
	2016		2015		2014
	(Dollars in thousands)
Long-lived assets (primarily power plants and related assets) located in:
United States	$	1,414,523	$	1,374,465	$	1,369,136
Kenya		327,157		375,257		330,200
Other foreign countries		199,559		107,407		90,735
Consolidated total	$	1,941,239	$	1,857,129	$	1,790,071

The following table presents revenues from major customers:

	Year Ended December 31,
	2016				2015				2014
	Revenues		%		Revenues		%		Revenues		%
	(Dollars in thousands)				(Dollars in thousands)				(Dollars in thousands)
Southern California Edison (1)	$	33,552		5.1	$	56,026		9.4	$	75,803		13.5
Southern California Public Power Authority  (1)		67,566		10.2		30,947		5.2		21,799		3.9
Sierra Pacific Power Company and Nevada Power Company (1)(2)		127,226		19.2		115,876		19.5		92,580		16.5
Hyundai (3)		100,856		15.2		93,131		15.7		38,174		6.8
KPLC (1)		109,270		16.5		86,545		14.6		86,074		15.4

________

(1)

Revenues reported in Electricity segment.

(2)

Subsidiaries of NV Energy, Inc.

(3)

Revenues related to the Sarulla project that are reported in Products segment.

XML

Note 21 - Transactions with Related Entities

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Related Party Transactions Disclosure [Text Block]

NOTE

21

 — TRANSACTIONS WITH RELATED ENTITIES

Transactions between the Company and related entities, other than those disclosed elsewhere in these financial are summarized below:

	Year Ended December 31,
	2016		2015		2014
	(Dollars in thousands)
Property rental fee expense paid to the Parent	$	—	$	303	$	1,821
Corporate financial, administrative, executive services, and research and development services provided to the Parent	$	—	$	148	$	148
Services rendered by an indirect shareholder of the Parent	$	—	$	15	$	51

The current asset due from the Parent at

December

31,

2015

in the amount of

$1,337,000

represented the net obligation resulting from ongoing operations and transactions with the Parent and is payable from available cash flow. Interest was computed on balances greater than

60

days at LIBOR plus

1%

(but not less than the change in the Israeli Consumer Price Index plus

4%)

compounded quarterly, and was accrued and paid to the Parent annually

.

The amount of such balance as of

December

31,

2015

is

$0.

Restructuring with the Parent

On

February

5,

2015,

the Tel Aviv Stock Exchange (“TASE”) approved the listing of the Company

’s common stock on the TASE. On

February

10,

2015,

the Company's common stock was successfully listed on the TASE. The TASE also confirmed that the Company will be included in the TA-

25

Index, which is the TASE flagship index that tracks the share prices of the

25

companies with the highest market capitalization on the exchange. The Company will remain subject to the rules and regulations of the New York Stock Exchange (“NYSE”) and of the U.S. Securities and Exchange Commission (“SEC”). Under the local regime for dual listing, the Company will use the same periodic reports, financial and other relevant disclosure information that The Company submits to the SEC and NYSE.

On

February

12,

2015,

the Company completed the share exchange transaction with its then-

Parent entity, Ormat Industries Ltd. ("OIL") following which, the Company became a noncontrolled public company and its public float increased from approximately

40%

to approximately

76%

of its total shares outstanding. Under the terms of the share exchange, OIL shareholders received

0.2592

shares in the Company for each share in OIL, or an aggregate of approximately

30.2

million shares, reflecting a net issuance of approximately

3.0

million shares (after deducting the

27.2

million shares that OIL held in the Company). Consequently, the number of total shares of the Company outstanding increased from approximately

45.5

million shares to approximately

48.5

million shares as of the closing of the share exchange.

In exchange, the Company also received

$15.4

million in cash,

$0.6

million in other assets and

$12.1

million in land and buildings and assumed

$0.5

million in liabilities. OIL's principal business purpose was to hold its interest in the Company and the transaction resulted in a transfer of non-material assets from OIL to the Company. Therefore, there was no change in the reporting entity as a result of the transaction and the Company recognized the transfer of net assets at their carrying value as presented in OIL's financial statements. Any activities of OIL will be accounted for prospectively by the Company

Corporate and administrative services agreement with the Parent

Ormat Systems and the Parent had agreements whereby Ormat Systems provided to the Parent, for a monthly fee of $

10,000

(adjusted annually, in part based on changes in the Israeli Consumer Price Index), certain corporate administrative services, including the services of executive officers. In addition, Ormat Systems agreed to provide the Parent with services of certain skilled engineers and other research and development employees at Ormat Systems’ cost plus

10%.

Lease agreements with the Parent

Ormat Systems had a rental agreement with the Parent entered into in

July

2004

for the sublease of office and manufacturing facilities in Yavne, Israel, for a monthly rent of

$52,000,

adjusted annually for changes in the Israeli Consumer Price Index, plus taxes and other costs to maintain the properties. The term of the rental agreement was for a period ending the earlier of: (i)

25

years from

July

1,

2004;

or (ii) the remaining periods of the underlying lease agreements between the Parent and the Israel Land Administration (which terminate between

2018

and

2047).

Effective

April

1,

2009,

Ormat Systems entered into an additional rental agreement with the Parent for the sublease of additional manufacturing facilities adjacent to the current manufacturing facilities in Yavne, Israel. The term of the additional rent agreement was to expire on the same day as the abovementioned lease agreement entered into in

July

2004.

Pursuant to the additional lease agreement, Ormat Systems paid a monthly rent of

$77,000,

adjusted annually for changes in the Israeli Consumer Price Index, plus tax and other costs to maintain the properties

.

Registration rights agreement

Prior to the closing of the Company

’s initial public offering in

November

2004,

the Company and the Parent entered into a registration rights agreement pursuant to which the Parent

may

require the Company to register its common stock for sale on Form S-

1

or Form S-

3.

The Company also agreed to pay all expenses that result from the registration of the Company’s common stock under the registration rights agreement, other than underwriting commissions for such shares and taxes. The Company has also agreed to indemnify the parent, its directors, officers and employees against liability that

may

result from their sale of the Company’s common stock, including Securities Act liabilities.

As of

February

12,

2015,

the above-mentioned agreements are no longer effective as a result of the restructuring transaction described above.

XML

Note 22 - Employee Benefit Plan

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Pension and Other Postretirement Benefits Disclosure [Text Block]

NOTE

22

— EMPLOYEE BENEFIT PLAN

401

(

k) Plan

The Company has a

401(k)

Plan (the “Plan”) for the benefit of its U.S. employees. Employees of the Company and its U.S. subsidiaries who have completed

one

year of service or who had

one

year of service upon establishment of the Plan are eligible to participate in the Plan. Contributions are made by employees through pretax deductions up to

60%

of their annual salary. In

2016,

2015

and

2014,

contributions made by the Company were matched up to a maximum of

3%,

2%

and

2%

of the employee

’s annual salary, respectively. The Company’s contributions to the Plan were

$1.0

million,

$0.6

million, and

$0.5

million for the years ended

December

31,

2016,

2015,

and

2014,

respectively.

Severance plan

The Company, through Ormat Systems, provides limited non-pension benefits to all current employees in Israel who are entitled to benefits in the event of termination or retirement in accordance with the Israeli Government sponsored programs. These plans generally obligate the Company to pay

one

month

’s salary per year of service to employees in the event of involuntary termination. There is no limit on the number of years of service in the calculation of the benefit obligation. The liabilities for these plans are recorded at each balance sheet date by determining the undiscounted obligation as if it were payable at that point in time. Such liabilities have been presented in the consolidated balance sheets as “liabilities for severance pay”. The Company has an obligation to partially fund the liabilities through regular deposits in pension funds and severance pay funds. The amounts funded amounted to

$12.8

million and

$14.2

million at

December

31,

2016

and

2015,

respectively, and have been presented in the consolidated balance sheets as part of “deposits and other”. The severance pay liability covered by the pension funds is not reflected in the financial statements as the severance pay risks have been irrevocably transferred to the pension funds. Under the Israeli severance pay law, restricted funds

may

not be withdrawn or pledged until the respective severance pay obligations have been met. As allowed under the program, earnings from the investment are used to offset severance pay costs. Severance pay expenses for the years ended

December

31,

2016,

2015,

and

2014

were

$2.3

million,

$2.5

million, and

$2.1

million, respectively, which are net of income (including loss) amounting to

$0.3

million,

$0.1

million, and

$(1.5)

million, respectively, generated from the regular deposits and amounts accrued in severance funds.

The Company expects to pay the following future benefits to its employees upon their reaching normal retirement age

:

			( Dollars in thousands )
Year ending December 31 :
201 7			$	1,867
201 8				2,497
201 9				1,655
20 20				1,119
20 21				1,400
20 22	-	2026		5,141
			$	13,679

The above amounts were determined based on the employees

’ current salary rates and the number of years’ service that will have been accumulated at their retirement date. These amounts do not include amounts that might be paid to employees that will cease working with the Company before reaching their normal retirement age.

XML

Note 23 - Commitments and Contingencies

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Commitments and Contingencies Disclosure [Text Block]

NOTE

23

— COMMITMENTS AND CONTINGENCIES

Geothermal resources

The Company, through its project subsidiaries in the United States, controls certain rights to geothermal fluids through certain leases with the Bureau of Land Management (“BLM”) or through private leases. Royalties on the utilization of the geothermal resources are computed and paid to the

lessors as defined in the respective agreements. Royalty expense under the geothermal resource agreements were

$17.1

million,

$15.4

million, and

$16.3

million for the years ended

December

31,

2016,

2015,

and

2014,

respectively.

Letters of credit

In the ordinary course of business with

customers, vendors, and lenders, the Company is contingently liable for performance under letters of credit totaling

$341.6

million at

December

31,

2016.

Management does not expect any material losses to result from these letters of credit because performance is not expected to be required, and, therefore, is of the opinion that the fair value of these instruments is

zero.

Purchase commitments

The Company purchases raw materials for inventories, construction-in-process and services from a variety of vendors. During the normal course of business, in order to manage manufacturing lead times and help assure adequate supply, the Company enters into agreements with contract manufacturers and suppliers that either allow them to procure goods and services based upon specifications defined by the Company, or that establish parameters defining the Company

’s requirements.

At

December

31,

2016,

total obligations related to such supplier agreements were approximately

$108.1

million (out of which approximately

$51.0

million relate to construction-in-process). All such obligations are payable in

2017.

Grants and royalties

The Company, through Ormat Systems, had historically, through

December

31,

2003,

requested and received grants for research and development from the Office of the Chief Scientist of the Israeli Government. Ormat Systems is required to pay royalties to the Israeli Government at a rate of

3.5%

to

5.0%

of the revenues derived from products and services developed using these grants.

No

royalties were paid for the years ended

December

31,

2016

,

2015,

and

2014.

The Company is not liable for royalties if the Company does not sell such products and services. Such royalties are capped at the amount of the grants received plus interest at LIBOR. The cap at

December

31,

2016

and

2015,

amounted to

$1.8

million and

$1.7

million, respectively, of which approximately

$0.8

million and

$0.8

million, respectively, represents interest based on the LIBOR rate, as defined above.

Lease commitments

At

December

31,

201

6,

2015

and

2014,

total lease expenses for leasing of land, building and equipment outside of the Puna lease (separately described in Note

13)

amounted to

$0.4

million,

$0.4

million and

$0.3

million respectively. The related future minimum lease payments are immaterial for each year.

In

2015,

t

he Company entered into a lease transaction for a fleet of vehicles. The lease transaction was classified as a capital lease and the leased vehicles were classified under Property, Plant and Equipment in total amount of

$6.9

million, representing vehicles that were received during

2015

and

2016.

The terms of the lease are monthly payments in equal installments over

5

years. The related future minimum lease payments are immaterial for each year.

Contingencies

● Jon Olson and Hilary Wilt, together with Puna Pono Alliance filed a complaint on February 17, 2015 in the Third Circuit Court for the State of Hawaii, requesting declaratory and injunctive relief requiring that PGV comply with an ordinance that the plaintiffs allege will prohibit PGV from engaging in night drilling operations at its KS- 16 well site. On May 17, 2015, the original complaint was amended to add the county of Hawaii and the State of Hawaii Department of Land and Natural Resources as defendants to the case. On October 10, 2016, the court issued its decision in response to each of the plaintiffs ’ and defendants’ motions for summary judgment, denying plaintiffs’ motion and granting defendant PGV's and the County of Hawaii’s cross motions for summary judgment, effectively rendering the plaintiffs’ action moot. On January 17, 2017, the plaintiffs filed a notice of appeal of the October 10, 2016 decision.  Procedural issues as to the ability of the plaintiffs to appeal the decision at this time, including the jurisdiction of the appellate court to near the appeal, are also before the court.

● On July 8, 2014, Global Community Monitor, LiUNA, and two residents of Bishop, California filed a complaint in the U.S. District Court for the Eastern District of California, alleging that Mammoth Pacific, L.P., the Company and Ormat Nevada are operating three geothermal generating plants in Mammoth Lakes, California (MP- 1, MP-II and PLES-I) in violation of the federal Clean Air Act and Great Basin Unified Air Pollution Control District rules. On June 26, 2015, in response to a motion by the defendants, the court dismissed all but one of the plaintiffs ’ causes of action. On January 6, 2017, the court issued its order regarding several pending motions, including plaintiffs’ motion for partial summary judgment, defendants' motion for summary judgment, defendants' motion to exclude and defendants' motion for leave to file a sur-reply. The impact of the court’s January 6 order is to deny the plaintiffs’ sole remaining cause of action.

● On April 5, 2012, the International Brotherhood of Electrical Workers Local 1260 (“Union”) filed a petition with the NLRB seeking to organize the operations and maintenance employees at the Puna project.   A global settlement was reached in principle in February 2016, which includes a Union disclaimer of interest, the withdrawal of letters from the Union to the NRLB and signed individual settlement agreements, all of which are immaterial. All issues are now settled and closed.

● In January 2014, Ormat learned that two former employees filed a “qui tam” complaint seeking damages, penalties and other relief of approximately $375 million, alleging that the Company and certain of its subsidiaries (collectively, the “Ormat Parties”) submitted fraudulent applications and certifications to obtain grants for the Puna and North Brawley projects. The U.S. Department of Justice declined to intervene. On October 25, 2016, the parties entered into a final settlement agreement  providing for the dismissal of the claim without any admission of wrongdoing by the Ormat Parties and payment of $11 million (inclusive of fees and costs). The settlement amount of $11 million was included in general and administrative expenses in the consolidated statements of operations and comprehensive income for the year ended December 31, 2016.  

● On March 29, 2016, a former local sales representative in Chile, Aquavant, S.A., filed a claim on the basis of unjust enrichment against Ormat ’s subsidiaries in the 27th Civil Court of Santiago, Chile. The claim requests that the court order Ormat to pay Aquavant  $4.6 million in connection with its activities in Chile, including the EPC contract for the Cerro Pabellon project and various geothermal concessions, plus 3.75% of Ormat geothermal products sales in Chile over the next 10 years. Pursuant to various petitions submitted by defendants, including a motion describing preliminary, procedural defenses, on August 18, 2016, and then on October 10, 2016, the 27th Civil Court issued a number of decisions, which include removal of the case to the 11th Civil Court of Santiago, thereby delaying a determination on the larger issues of jurisdiction and competency of the Chilean courts as a substantive (and not procedural) defense.   The Company believes that it has valid defenses under law, and intends to defend itself vigorously.

●   On August 5, 2016, George Douvris, Stephanie Douvris, Michael Hale, Cheryl Cacocci, Hillary E. Wilt and Christina Bryan, acting for themselves and on behalf of all other similarly situated residents of the lower Puna District, filed a complaint in the Third Circuit Court for the State of Hawaii seeking certification of a class action for preliminary and permanent injunctive relief, consequential and punitive damages, attorney’s fees and statutory interest against PGV and other presently unknown defendants. The complaint purports that injuries and other damages in an undisclosed amount were caused to the plaintiffs as a result of an alleged toxic release by PGV in the wake of Hurricane Iselle in August 2014. On August 25, 2016, the Company filed to remove the case to the U.S. District Court for the District of Hawaii. On  December 12, 2016, the District Court granted plaintiffs’ motion for joinder of HELCO as an additional defendant, to amend the complaint, and to remand the case back to the Third Circuit Court. The Company believes that it has valid defenses under law, and intends to defend itself vigorously.

● On May 21, 2014, Elko County, Nevada appealed to the Supreme Court of Nevada the Nevada Governor's Office of Energy ’s award of an energy tax abatement to ORNI 42 LLC for our Tuscarora power plant. Lander County, Nevada similarly appealed the Office of Energy’s Award of an energy tax abatement to ORNI 39 LLC for one of our McGinness power plant. Both of the appeals request that the Court overturn the Office of Energy’s decision and deny, retroactively and going forward, the tax abatement benefits for the full 20 year period, valued at approximately $18.6 million for one of our McGinness power plant and approximately $6.2 million for our Tuscarora power plant, of which only a small portion was utilized as of September 30, 2016.  Following full briefing on both plaintiffs’ and defendants’ motions for summary judgment, on December 21, 2016, the Supreme Court of Nevada issued its Order of Affirmance of the judgement of the District Court denying the petitions for judicial review of both Lander County and Elko County, and affirming ORNI 39 and ORNI 42's rights to obtain the partial property tax abatements for their respective facilities.

●   On June 20, 2016, Nadia Garcia, individually and as successor in interest to Thomas Garcia Valenzuela, and as guardian ad litem to Emerie Garcia, Khamilla Garcia and Reyene Adam, filed a complaint against Ormat Technologies, Ormat Nevada and Ormesa LLC in the Superior Court of Imperial County seeking unspecified monetary damages. The complaint alleges that the Ormat defendants caused the wrongful death, personal injury and other harm to Thomas Garcia when he was employed by Martin Hydroblasting Services, Inc. and suffered injuries leading to his death while performing work at the Ormesa plant site on or around March 31, 2016. Early discovery and conferences are underway. The insurer of the deceased’s employer, and Ormat’s insurer, have accepted tender of this claim and are providing Ormat with a defense in the lawsuit, subject to reservation of rights to deny coverage under the policy and under the law.

In addition, from time to time, the Company is named as a party to various other lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our business. These actions typically seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to such lawsuits, claims and proceedings, the Company accrues reserves when a loss is probable and the amount of such loss can be reasonably estimated. It is the opinion of the Company

’s management that the outcome of these proceedings, individually and collectively, will not be material to the Company’s consolidated financial statements as a whole.

XML

Note 24 - Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Quarterly Financial Information [Text Block]

NOTE

24

— QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	Three Months Ended
	Mar. 31, 2015			June 30, 2015			Sept. 30, 2015			Dec. 31, 2015			Mar. 31, 2016			June 30, 2016			Sept. 30, 2016			Dec. 31, 2016
	(Dollars in thousands, except per share amounts)
Revenues:
Electricity	$	89,953		$	90,926		$	97,245		$	97,796		$	107,868		$	104,001		$	109,795		$	114,628
Product		30,278			49,561			65,607			73,278			43,726			55,860			74,822			51,891
Total revenues		120,231			140,487			162,852			171,074			151,594			159,861			184,617			166,519
Cost of revenues:
Electricity		55,581			62,522			61,501			63,008			63,686			62,243			66,481			69,163
Product		20,625			27,182			42,019			43,927			24,035			31,822			43,647			30,719
Total cost of revenues		76,206			89,704			103,520			106,935			87,721			94,065			110,128			99,882
Gross profit		44,025			50,783			59,332			64,139			63,873			65,796			74,489			66,637
Operating expenses:
Research and development expenses		363			414			335			668			349			595			1,086			732
Selling and marketing expenses		3,433			4,283			4,383			3,978			3,675			3,668			4,793			4,288
General and administrative expenses		10,204			7,443			7,950			9,185			8,749			8,783			19,093			10,085
Write-off of unsuccessful exploration activities		174			--			185			1,220			557			863			1,294			303
Operating income		29,851			38,643			46,479			49,088			50,543			51,887			48,223			51,229
Other income (expense):
Interest income		9			44			53			191			320			245			266			140
Interest expense, net		(17,828	)		(18,859	)		(17,748	)		(18,142	)		(16,023	)		(18,401	)		(17,137	)		(15,828	)
Foreign currency translation and transaction gains (losses)		(1,366	)		(571	)		1,296			(981	)		1,962			(4,332	)		(222	)		(2,942	)
Income attributable to sale of tax benefits		5,552			4,731			8,634			6,514			4,398			4,519			3,463			4,123
Other non-operating income (expense), net		283			(1,675	)		(131	)		(468	)		191			49			(5,546	)		(39	)
Income (loss) from continuing operations, before income taxes and equity in income of investees		16,501			22,313			38,583			36,202			41,391			33,967			29,047			36,683
Income tax benefit (provision)		(5,459	)		(6,056	)		38,211			(11,438	)		(9,509	)		(7,890	)		(11,988	)		(2,450	)
Equity in income (losses) of investees		(775	)		(984	)		(3,133	)		(616	)		(937	)		(1,144	)		(2,653	)		(3,001	)
Net income (loss)		10,267			15,273			73,661			24,148			30,945			24,933			14,406			31,232
Net loss (income) attributable to noncontrolling interest		(235	)		(859	)		(1,522	)		(1,160	)		(1,674	)		(584	)		(2,326	)		(3,002	)
Net income (loss) attributable to the Company's stockholders	$	10,032		$	14,414		$	72,139		$	22,988		$	29,271		$	24,349		$	12,080		$	28,230
Earnings (loss) per share attributable to the Company's stockholders
Basic:
Net income	$	0.21		$	0.29		$	1.47		$	0.47		$	0.60		$	0.49		$	0.24		$	0.57
Diluted:
Net income	$	0.21		$	0.28		$	1.41		$	0.46		$	0.59		$	0.49		$	0.24		$	0.56
Weighted average number of shares used in computation of earnings per share attributable to the Company's stockholders:
Basic		47,244			48,881			49,023			49,074			49,173			49,456			49,599			49,647
Diluted		48,079			50,600			51,113			49,668			49,782			50,137			50,289			50,293

XML

Note 25 - Subsequent Events

12 Months Ended

Dec. 31, 2016

Notes to Financial Statements

Subsequent Events [Text Block]

NOTE

25

— SUBSEQUENT EVENTS

Cash dividend

On

February

28,

2017,

the Company

’s Board of Directors declared, approved and authorized payment of a quarterly dividend of

$8.4

million

($0.17

per share) to all holders of the Company’s issued and outstanding shares of common stock on

March

15,

2017,

payable on

March

29,

2017.

XML

Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Description Of Business [Policy Text Block]

Business

Ormat Technologies, Inc. (the “Company”) is primarily engaged in the geothermal and recovered energy business, including the supply of equipment that is manufactured by the Company and the design and construction of power plants for projects owned by the Company or for

third

parties. The Company owns and operates geothermal and recovered energy-based power plants in various countries, including the United States of America (“U.S.”), Kenya, and Guatemala. The Company

’s equipment manufacturing operations are located in Israel.

Most of the Company

’s domestic power plant facilities are Qualifying Facilities under the Public Utility Regulatory Policies Act of

1978

(“PURPA”). The power purchase agreements (“PPAs”) for certain of such facilities are dependent upon their maintaining Qualifying Facility status. Management believes that all of the facilities located in the U.S. were in compliance with Qualifying Facility status requirements as of

December

31,

2016.

Dividend Declared [Policy Text Block]

Cash dividends

During the years ended

December

31,

2016,

2015,

and

2014,

the Company’s Board of Directors declared, approved, and authorized the payment of cash dividends in the aggregate amount of

$25.7

million

($0.52

per share),

$12.7

million

($0.26

per share), and

$9.6

million

($0.21

per share), respectively. Such dividends were paid in the years declared.

Rounding [Policy Text Block]

Rounding

Dollar amounts, except per share data, in the notes to these financial statements are rounded to the closest

$1,000,

unless otherwise indicated

.

Basis of Accounting, Policy [Policy Text Block]

Basis of presentation

The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and include the accounts of the Company and of all majority-owned subsidiaries in which the Company exercises control over operating and financial policies, and variable interest entities in which the Company has an interest and is the primary beneficiary. Intercompany accounts and transactions have been eliminated in consolidation

.

Investments in less-than-majority-owned entities or other entities in which the Company exercises significant influence over operating and financial policies are accounted for using the equity method of accounting or consolidated if they are a variable interest entity in which the Company has an interest and is the primary beneficiary. Under the equity method, original investments are recorded at cost and adjusted by the Company

’s share of undistributed earnings or losses of such companies. The Company’s earnings or losses in investments accounted for under the equity method have been reflected as “equity in income (losses) of investees, net” on the Company’s consolidated statements of operations and comprehensive income (loss).

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and cash equivalents

The Company considers all highly liquid instruments, with an original maturity of

three

months or less, to be cash equivalents

.

Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]

Restricted cash, cash equivalents

, and marketable securities

Under the terms of certain long-term debt agreements, the Company is required to maintain certain debt service reserves, cash collateral and operating fund accounts that have been classified as restricted cash and cash equivalents. Funds that will be used to satisfy obligations due during the next

twelve

months are classified as current restricted cash and cash equivalents, with the remainder classified as non-current restricted cash and cash equivalents. Such amounts were invested primarily in money market accounts and commercial paper with a minimum investment grade of “AA”.

Concentration Risk, Credit Risk, Policy [Policy Text Block]

Concentration of credit risk

Financial instruments which potentially subject the Company to concentration of credit risk consist principally of temporary cash investments and accounts receivable

.

The Company places its temporary cash investments with high credit quality financial institutions located in the U.S. and in foreign countries. At

December

31,

2016

and

2015,

the Company had deposits totaling

$72.5

million and

$19.0

million, respectively, in

seven

U.S. financial institutions that were federally insured up to

$250,000

per account. At

December

31,

2016

and

2015,

the Company

’s deposits in foreign countries of approximately

$166.2

million and

$181.0

million, respectively, were not insured.

At

December

31,

2016

and

2015,

accounts receivable related to operations in foreign countries amounted to

approximately

$53.3

million and

$27.8

million, respectively. At

December

31,

2016,

and

2015,

accounts receivable from the Company’s major customers (see Note

20)

amounted to approximately

60%

and

66%,

respectively, of the Company’s accounts receivable.

The Company has historically been able to collect on substantially all of its receivable balances, and accordingly, no provision for doubtful accounts has been made.

Inventory, Policy [Policy Text Block]

Inventories

Inventories consist primarily of raw material parts and sub-assemblies for power units, and are stated at the lower of cost or market value, using the weighted-average cost method. Inventories are reduced by a provision for slow-moving and obsolete inventories. This provision was

not

material at

December

31,

2016

and

2015.

Deposit Contracts, Policy [Policy Text Block]

Deposits and other

Deposits and other consist primarily of performance bonds for construction projects, long-term insurance contract and receivables, and derivative instruments.

Deferred Charges, Policy [Policy Text Block]

Deferred charges

Deferred charges represent prepaid income taxes on intercompany sales. Such amounts are amortized using the straight-line method and included in income tax provision over the life of the related property, plant and equipment.

Property, Plant and Equipment, Policy [Policy Text Block]

Property, plant and equipment, net

Property, plant and equipment are stated at cost. All costs associated with the acquisition, development and construction of power plants operated by the Company are capitalized. Major improvements are capitalized and repairs and maintenance (including major maintenance) costs are expensed. Power plants operated by the Company, which include geothermal wells and exploration and resource development costs, are depreciated using the straight-line method over their estimated useful lives, which range from

15

to

30

years. The other assets are depreciated using the straight-line method over the following estimated useful lives of the assets:

Buildings (in years)		25
Leasehold improvements (in years)	15	-	20
Machinery and equipment — manufacturing and drilling (in years)		10
Machinery and equipment — computers (in years)	3	-	5
Office equipment — furniture and fixtures (in years)	5	-	15
Office equipment — other (in years)	5	-	10
Automobiles (in years)	5	-	7

The cost and accumulated depreciation of items sold or retired are removed from the accounts. Any resulting gain or loss recognized currently and is recorded in the accompanying statements of operations.

The Company capitalizes interest costs as part of constructing power plant facilities. Such capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset

’s estimated useful life. Capitalized interest costs amounted to

$3.3

million,

$4.1

million, and

$3.2

million for the years ended

December

31,

2016,

2015,

and

2014,

respectively.

Cash Grant [Policy Text Block]

Cash Grants

From

2009

to

2014,

the Company was awarded cash grants from the U.S. Department of the Treasury (“U.S. Treasury”) for Specified Energy Property in Lieu of Tax Credits under Section

1603

of the American Recovery and Reinvestment Act of

2009

(“ARRA”). The Company recorded the cash grant as a reduction in the carrying value of the related plant and amortized the grants as a reduction in depreciation expense over the plant’s estimated useful life.

Exploratory Drilling Costs Capitalization and Impairment, Policy [Policy Text Block]

Exploration and development costs

The Company capitalizes costs incurred in connection with the exploration and development of geothermal resources once it acquires land rights to the potential geothermal resource. Prior to acquiring land rights, the Company makes an initial assessment that an economically feasible geothermal reservoir is probable on that land. The Company determines the economic feasibility of potential geothermal resources internally, with all available data and external assessments vetted through the exploration department and occasionally using outside service providers. Costs associated with the initial assessment are expensed and included in cost of electricity revenues in the consolidated statements of operations and comprehensive income (loss). Such costs were immaterial during the years ended

December

31,

2016,

2015,

and

2014.

It normally takes

two

to

three

years from the time active exploration of a particular geothermal resource begins to the time a production well is in operation, assuming the resource is commercially viable. However, in certain sites the process

may

take longer due to permitting delays, transmission constrains or any other commercial milestones that are required to be reached in order to pursue the development process.

In most cases, the Company obtains the right to conduct the geothermal development and operations on land owned by the Bureau of Land Management (“BLM”), various states or with private parties. In consideration for certain of these leases, the Company

may

pay an up-front bonus payment which is a component of the competitive lease process. The up-front bonus payments and other related costs, such as legal fees, are capitalized and included in construction-in-process. The annual land lease payments made during the exploration, development and construction phase are expensed as incurred and included in “electricity cost of revenues” in the consolidated statements of operations and comprehensive income (loss). Upon commencement of power generation on the leased land, the Company begins to pay to the lessors long-term royalty payments based on the utilization of the geothermal resources as defined in the respective agreements. Such payments are expensed when the related revenues are earned and included in “electricity cost of revenues” in the consolidated statements of operations and comprehensive income (loss).

Following the acquisition of land rights to the potential geothermal resource, the Company conducts further studies and surveys, including water and soil analyses among others, and augments its database with the results of these studies. The Company then initiates a suite of geophysical surveys to assess the resource and determine drilling locations. If the results of these activities support the initial assessment of the feasibility of the geothermal resource, the Company then proceeds to exploratory drilling and other related activities which

may

include drilling of temperature gradient holes, drilling of slim holes, building access roads to drilling locations, drilling full size production and/or injection wells and flow tests. If the slim hole supports a conclusion that the geothermal resource will support a commercially viable power plant, it

may

be converted to a full-size commercial well, used either for extraction or re-injection or geothermal fluids, or be used as an observation well to monitor and define the geothermal resource. Costs associated with these activities and other directly attributable costs, including interest once physical exploration activities begin and permitting costs are capitalized and included in “construction-in-process”. If the Company concludes that a geothermal resource will not support commercial operations, capitalized costs are expensed in the period such determination is made.

When deciding whether to continue holding lease rights and/or to pursue exploration activity, we diligently prioritize our prospective investments, taking into account resource and probability assessments in order to make informed decisions about whether a particular project will support commercial operations

. As a result, write-off of unsuccessful activities for the year ended

December

31,

2016,

2015

and

2014,

was

$3.0

million,

$1.6

million, and

$15.4

million. In

2016

and

2015,

the write-offs included the exploration costs related to the Company’s exploration activities primarily in the Twilight site in Oregon and the Maui site in Hawaii of

$1.0

million, respectively. In

2014,

the write-offs included the exploration costs related to the Company’s exploration activities in the Wister site in California of

$8.1

million and the Mount Spur site in Alaska of

$7.3

million.

Grants received from the U.S. Department of Energy (“DOE”) are offset against the related exploration and development costs. Such grants amounted to

$0.3

million,

$0.8

million, and

$1.7

million for the years ended

December

31,

2016,

2015,

and

2014,

respectively.

All exploration and development costs that are being capitalized, including the up-front bonus payments made to secure land leases, will be depreciated over their estimated useful lives when the related geothermal power plant is substantially complete and ready for use. A geothermal power plant is substantially complete and ready for use when electricity generation commences.

Asset Retirement Obligations, Policy [Policy Text Block]

Asset retirement obligation

The Company records the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. The Company

’s legal liabilities include plugging wells and post-closure costs of power producing sites. When a new liability for asset retirement obligations is recorded, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. At retirement, the obligation is settled for its recorded amount at a gain or loss.

Deferred Financing And Lease Transaction Costs [Policy Text Block]

Deferred financing and lease transaction costs

Deferred financing costs are amortized over the term of the related obligation using the effective interest method. Amortization of deferred financing costs is presented as interest expense in the consolidated statements of operations and comprehensive income (loss). Accumulated amortization related to deferred financing costs amounted to

$31.1

million and

$37.2

million at

December

31,

2016

and

2015,

respectively. Amortization expense for the years ended

December

31,

2016,

2015,

and

2014

amounted to

$6.9

million,

$8.8

million, and

$6.5

million, respectively. During the years ended

December

31,

2016,

2015

and

2014

amounts of

$0.1

million,

$0.5

million and

$0.7

million, respectively, were written-off as a result of the extinguishment of liability.

Deferred transaction costs relating to the Puna operating lease (see Note

13)

in the amount of

$4.2

million are amortized using the straight-line method over the

23

-year term of the lease. Amortization of deferred transaction costs is presented in cost of revenues in the consolidated statements of operations and comprehensive income (loss). Accumulated amortization related to deferred lease costs amounted to

$2.1

million and

$2.0

million at

December

31,

2016

and

2015,

respectively. Amortization expense for each of the years ended

December

31,

2016,

2015,

and

2014

amounted to

$0.2

million.

Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]

Goodwill

Goodwill represents the excess of the fair value of consideration transferred in the Guadeloupe business combination transaction over the fair value of tangible and intangible assets acquired net of the fair value of liabilities assumed and the fair value of any noncontrolling interest in the acquisition. Goodwill is not amortized but rather subject to periodic impairment testing on an annual basis or if an event occurs or circumstances change that would more likely than not reduce the fair value of reporting unit below its carrying amount.

Intangible Assets, Finite-Lived, Policy [Policy Text Block]

Intangible assets

Intangible assets consist of allocated acquisition costs of PPAs, which are amortized using the straight-line method over the

13

to

25

-year terms of the agreements (see Note

10

).

Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]

Impairment of long-lived assets and long-lived assets to be disposed of

The Company evaluates long-lived assets, such as property, plant and equipment and construction-in-process for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset

may

not be recoverable. Factors which could trigger an impairment include, among others, significant underperformance relative to historical or projected future operating results, significant changes in the Company

’s use of assets or its overall business strategy, negative industry or economic trends, a determination that an exploration project will not support commercial operations, a determination that a suspended project is not likely to be completed, a significant increase in costs necessary to complete a project, legal factors relating to its business or when it concludes that it is more likely than not that an asset will be disposed of or sold.

The Company tests its operating plants that are operated together as a complex for impairment at the complex level because the cash flows of such plants result from significant shared operating activities. For example, the operating power plants in a complex are managed under a combined operation management generally with

one

central control room that controls all of the power plants in a complex and

one

maintenance group that services all of the power plants in a complex. As a result, the cash flows from individual plants within a complex are not largely independent of the cash flows of other plants within the complex. The Company tests for impairment its operating plants which are not operated as a complex as well as its projects under exploration, development or construction that are not part of an existing complex at the plant or project level. To the extent an operating plant becomes part of a complex, the Company will test for impairment at the complex level.

Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated future net undiscounted cash flows expected to be generated by the asset. The significant assumptions that the Company uses in estimating its undiscounted future cash flows include: (i) projected generating capacity of the complex or power plant and rates to be received under the respective PPA(s)

and expected market rates thereafter

and (ii) projected operating expenses of the relevant complex or power plant. Estimates of future cash flows used to test recoverability of a long-lived asset under development also include cash flows associated with all future expenditures necessary to develop the asset.

If the assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. Management believes that no impairment exists for long-lived assets; however, estimates as to the recoverability of such assets

may

change based on revised circumstances. If actual cash flows differ significantly from the Company

’s current estimates, a material impairment charge

may

be required in the future.

Derivatives, Policy [Policy Text Block]

Derivative instruments

Derivative instruments (including certain derivative instruments embedded in other contracts) are measured at their fair value and recorded as either assets or liabilities unless exempted from derivative treatment as a normal purchase and sale. All changes in the fair value of derivatives are recognized in earnings unless specific hedge criteria are met, which requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

The Company maintains a risk management strategy that incorporates the use of swap contracts and put options on oil and natural gas prices, forward exchange contracts, interest rate swaps, and interest rate caps to minimize significant fluctuation in cash flows and/or earnings that are caused by oil and natural gas prices, exchange rate or interest rate volatility. Gains or losses on contracts that initially qualify for cash flow hedge accounting, net of related taxes, are included as a component of other comprehensive income or loss and accumulated other comprehensive income or loss are subsequently reclassified into earnings when the hedged forecasted transaction affects earnings. Gains or losses on contracts that are not designated as a cash flow hedge are included currently in earnings.

Foreign Currency Transactions and Translations Policy [Policy Text Block]

Foreign currency translation

The U.S. dollar is the functional currency for all of the Company

’s consolidated operations and those of its equity affiliates except for the Guadeloupe power plant. For those entities, all gains and losses from currency translations are included within the line item “Derivatives and foreign currency transaction gains (losses)” within the consolidated statements of operations and comprehensive income (loss). The Euro is the functional currency of the Guadeloupe power plant and thus gains and losses from currency translation adjustments related to Guadeloupe are included as currency translation adjustments in accumulated other comprehensive income in the consolidated statements of equity and in comprehensive income.

Comprehensive Income, Policy [Policy Text Block]

Comprehensive income (loss) reporting

Comprehensive income (loss) includes net income or loss plus other comprehensive income (loss), which for the Company consists of changes in unrealized gains or losses in respect of the Company

’s share in derivatives instruments of unconsolidated investment, foreign currency translation adjustments and the mark-to-market gains or losses on derivative instruments designated as a cash flow hedge. For the years ended

December

31,

2016,

2015

and

2014,

the Company reclassified

$9

thousand,

$27

thousand and

$141

thousand, respectively, from other comprehensive income, of which

$12.0

thousand,

$44

thousand and

$228

thousand, respectively, were recorded to reduce interest expense and

$3.0

thousand,

$17

thousand and

$87

thousand, respectively, were recorded against the income tax provision, in the consolidated statements of operations and comprehensive income (loss).

Revenue Recognition, Policy [Policy Text Block]

Revenues and cost of revenues

Revenues are primarily related to: (i) sale of electricity from geothermal and recovered energy-based power plants owned and operated by the Company and (ii) geothermal and recovered energy-based power plant equipment engineering, sale, construction and installation, and operating services.

Revenues related to the sale of electricity from geothermal and recovered energy-based power plants and capacity payments are recorded based upon output delivered and capacity provided at rates specified under relevant contract terms. For PPAs agreed to, modified, or acquired in business combinations on or after

July

1,

2003,

the Company determines whether such PPAs contain a lease element requiring lease accounting. Revenue from such PPAs are accounted for in electricity revenues. The lease element of the PPAs is also assessed in accordance with the revenue arrangements with multiple deliverables guidance, which requires that revenues be allocated to the separate earnings processes based on their relative fair value. PPAs with minimum lease rentals which vary over time are generally recognized on the straight-line basis over the term of the PPAs. PPAs with contingent rentals are recognized when earned.

Revenues from engineering, operating services, and parts and product sales are recorded upon providing the service or delivery of the products and parts and when collectability is reasonably assured. Revenues from the supply and/or construction of geothermal and recovered energy-based power plant equipment and other equipment to

third

parties are recognized using the percentage-of-completion method. Revenue is recognized based on the percentage relationship that incurred costs bear to total estimated costs. Costs include direct material, labor, and indirect costs. Selling, marketing, general, and administrative costs are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in job performance, job conditions, and estimated profitability, including those arising from contract penalty provisions and final contract settlements,

may

result in revisions to costs and revenues and are recognized in the period in which the revisions are determined

.

In specific instances where there is a lack of dependable estimates or inherent risks cause forecast to be doubtful, then the completed-contract method is followed. Revenue is recognized when the contract is substantially complete and when collectability is reasonably assured. Costs that are closely associated with the project are deferred as contract costs and recognized similarly to the associated revenues.

Standard Product Warranty, Policy [Policy Text Block]

Warranty on products sold

The Company generally provides a

one

-year warranty against defects in workmanship and materials related to the sale of products for electricity generation. Estimated future warranty obligations are included in operating expenses in the period in which the related revenue is recognized. Such charges are immaterial for the years ended

December

31,

2016,

2015,

and

2014

.

Research and Development Expense, Policy [Policy Text Block]

Research and development

Research and development costs incurred by the Company for the development of existing and new geothermal, recovered energy and remote power technologies are expensed as incurred. Grants received from the DOE are offset against the related research and development expenses. Such grants amounted to

$0

million,

$0

million, and

$0.6

million for the years ended

December

31,

2016,

2015,

and

2014,

respectively

.

Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]

Stock-based compensation

The Company accounts for stock-based compensation using the fair value method whereby compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the requisite employee service period (generally the vesting period of the grant). Prior to

2016,

the Company used the Black-Scholes formula to estimate the fair value of the stock-based compensation. In

2016,

the Company used the Exercise Multiple-Based Lattice SAR-Pricing Model to value the stock-based compensation awards to reflect accumulated historic data retained of behavioral parameters.

Tax Monetization Transactions Policy [Policy Text Block]

Tax monetization Transactions

The Company has

three

tax monetization transactions, OPC, ORTP and Opal, as described in Note

14.

  The purpose of these transactions is to form tax partnerships, whereby investors provide cash in exchange for equity interests that provide the holder a right to the majority of tax benefits associated with a renewable energy project.  We account for a portion of the proceeds from the transaction as debt under ASC

470.

  Given that a portion of these transactions is structured as a purchase of an equity interest we also classify a portion as noncontrolling interest consistent with guidance in ASC

810.

  The portion recorded to noncontrolling interest is initially measured as the fair value of the discounted Tax Attributes and cash distributions which represents the partner's residual economic interest.  The residual proceeds is recognized as the initial carrying value of the debt which is classified as a liability associated with sale tax benefits. We apply the effective interest rate method to the liability component as described by ASC

835

and CON

7.

  The tax benefits and cash distributions realized by the partner each period are treated as the debt servicing amounts, giving rise to income attributable to the sale of tax benefits.  The deferred transaction costs have been capitalized and amortized using the effective interest method.

Income Tax, Policy [Policy Text Block]

Income taxes

Income taxes are accounted for using the asset and liability approach, which requires the recognition of taxes payable or refundable for the current year and deferred tax assets and liabilities for the future tax consequences of events that have been recognized in the Company

’s financial statements or tax returns. The measurement of current and deferred tax assets and liabilities are based on provisions of the enacted tax law. The effects of future changes in tax laws or rates are not anticipated. The Company accounts for investment tax credits and production tax credits as a reduction to income taxes in the year in which the credit arises. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that, based on available evidence, are not, more likely than not expected to be realized. A full valuation allowance has been established to offset the Company’s U.S. deferred tax assets. Tax benefits from uncertain tax positions are recognized only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. Interest and penalties assessed by taxing authorities on an underpayment of income taxes are included as a component of income tax provision in the consolidated statements of operations and comprehensive income.

Earnings Per Share, Policy [Policy Text Block]

Earnings (loss) per share

Basic earnings (loss) per share attributable to the Company

’s stockholders (“earnings (loss) per share”) is computed by dividing net income or loss attributable to the Company’s stockholders by the weighted average number of shares of common stock outstanding for the period. The Company does not have any equity instruments that are dilutive, except for stock-based awards.

The table below shows the reconciliation of the number of shares used in the computation of basic and diluted earnings per share

:

	Year Ended December 31,
	2016		2015		2014
	(In thousands)
Weighted average number of shares used in computation of basic earnings per share		49,469		48,562		45,508
Add:
Additional shares from the assumed exercise of employee stock options		671		625		351
Weighted average number of shares used in computation of diluted earnings per share		50,140		49,187		45,859

The number of stock-based awards that could potentially dilute future earnings per share and were not included in the computation of diluted earnings per share because to do so would have been anti-dilutive was

102,793,

467,766,

and

3,237,593,

respectively, for the years ended

December

31,

2016,

2015,

and

2014.

Use of Estimates, Policy [Policy Text Block]

Use of estimates in preparation of financial statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of such financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. The most significant estimates with regard to the Company

’s consolidated financial statements relate to the useful lives of property, plant and equipment, impairment of long-lived assets and assets to be disposed of, revenue recognition of product sales using the percentage of completion method, asset retirement obligations, and the provision for income taxes.

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Pronouncements

New accounting pronouncements effective in the year ended

December

31,

2016

Amendments to Fair Value Measurement

In

June

2015,

the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”)

2015

-

10,

Amendment to Fair Value Measurement, Subtopic

820

-

10.

The amendment provides that the reporting entity shall disclose for each class of assets and liabilities measured at fair value in the statement of financial position the following information: for recurring fair value measurements, the fair value measurement at the end of the reporting period, and for non-recurring fair value measurement, the fair value measurement at the relevant measurement date and the reason for the measurement. The amendments in this update are effective for annual reporting periods beginning after

December

15,

2015,

including interim periods within those reporting periods. The adoption of this guidance did not have a material impact on the Company

’s consolidated financial statements.

Amendments to the Consolidation Analysis

In

February

2015,

the FASB issued ASU

2015

-

02,

Amendments to the Consolidation Analysis, Topic

810.

The update provides that all reporting entities that hold a variable interest in other legal entities will need to re-evaluate their consolidation conclusions and potentially revise their disclosures. This amendment affects both variable interest entity (“VIE”) and voting interest entity (“VOE”) consolidation models. The update does not change the general order in which the consolidation models are applied. A reporting entity that holds an economic interest in, or is otherwise involved with, another legal entity (i.e. has a variable interest) should

first

determine if the VIE model applies, and if so, whether it holds a controlling financial interest under that model. If the entity being evaluated for consolidation is not a VIE, then the VOE model should be applied to determine whether the entity should be consolidated by the reporting entity. Since consolidation is only assessed for legal entities, the determination of whether there is a legal entity is important. It is often clear when the entity is incorporated, but unincorporated structures can also be legal entities and judgment

may

be required to make that determination. The update contains a new example that highlights the discretion used to make this legal entity determination. The update is effective for annual reporting periods beginning after

December

15,

2015,

including interim periods within those reporting periods. The adoption of this guidance did not have a material impact on the Company

’s consolidated financial statements.

Simplifying the Presentation of Debt Costs

In

April

2015,

the FASB issued ASU

2015

-

03,

Interest-Imputation of Interest: Simplifying the Presentation of Debt Costs, Subtopic

835

-

30.

The update provides that debt issuance costs related to a recognized debt liability be presented in the balance sheet as direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The amendments in this update are effective for financial statements issued for fiscal years beginning after

December

15,

2015,

and interim periods within those fiscal years. The Company retrospectively adopted this update in its interim period beginning

January

1,

2016.

The impact of the adoption resulted in a reclassification of debt issuance costs totaling $

17.7

million and

$19.1

million as of

December

31,

2016

and

December

31,

2015,

respectively.

In

August

2015,

the FASB issued ASU

2015

-

15,

Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements, Subtopic

835

-

30.

The update clarifies that given the absence of authoritative guidance within Update

2015

-

03

for debt issuance costs described below, debt issuance costs related to line-of-credit arrangements can be deferred and presented as assets and subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings under the line-of-credit arrangement. The amendments in this update are effective for financial statements issued for fiscal years beginning after

December

15,

2015,

and interim periods within those fiscal years. The Company adopted this update in its interim period beginning

January

1,

2016

and continues to present debt issuance costs related to such line-of-credit arrangements as assets amortized ratably over the respective term of the line-of credit arrangements. Debt issuance costs related to such line-of-credit arrangements as of

December

31,

2016

and

December

31,

2015,

totaled

$1.1

million and

$1.0

million, respectively.

New accounting pronouncements effective in future periods

Business Combinations

In

January

2017,

the FASB issued ASU

2017

-

01,

Business Combinations (Topic

805).

The update clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this update primarily provide a screen to determine when a set of assets and activities is not a business and by that reduces the number of transactions that need to be further evaluated. The amendments in this update should be applied prospectively and are effective for financial statements issued for fiscal years beginning after

December

15,

2017,

and interim periods within those fiscal years. Early adoption is permitted. 

The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Statement of Cash Flows

In

November

2016,

the FASB issued ASU

2016

-

018,

Statement of Cash Flows (Topic

230)

– Restricted Cash. The amendments in this update require that a statement of cash flows explain the changes during the period in total cash, cash equivalents, and the amounts generally described as restricted cash or cash equivalents. Therefore, amounts of restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendments in this update should be applied retrospectively for each period presented and are effective for financial statements issued for fiscal years beginning after

December

15,

2017,

and interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Intra-Entity Transfers of Assets Other than Inventory

 

     In

October

2016,

the FASB issued ASU

2016

-

16,

Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory. The amendments in this update require that the entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The new guidance does not apply to intra-entity transfers on inventory. The amendments in this update should be applied for each period presented and are effective for financial statements issued for fiscal years beginning after

December

15,

2017,

and interim periods within those fiscal years. The modified retrospective approach will be required for transition to the new guidance, with cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. Early adoption is permitted in the

first

quarter of

2017.

The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Interests Held through Related Parties that are under Common Control

 

     In

October

2016,

the FASB issued ASU

2016

-

17,

Consolidation (Topic

810):

Interests held through Related Parties that are under Common Control. The amendments in this update require that if a decision maker is required to evaluate whether it is the primary beneficiary of a VIE, it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The amendments in this update should be applied retrospectively for each period presented and are effective for financial statements issued for fiscal years beginning after

December

15,

2016,

and interim periods within those fiscal years. The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Improvement to Employee Share-Based Payment Accounting

In

March

2016,

the FASB issued ASU

2016

-

09,

Improvement to Employee Share-Based Payment Accounting, an

 update to the guidance on stock-based compensation. Under the new guidance, all excess tax benefits and tax deficiencies will be recognized in the income statement as they occur. This will replace the current guidance, which requires tax benefits that exceed compensation cost (windfalls) to be recognized in equity. It will also eliminate the need to maintain a “windfall pool,” and will remove the requirement to delay recognizing a windfall until it reduces current taxes payable. The new guidance will also change the cash flow presentation of excess tax benefits, classifying them as operating inflows, consistent with other cash flows related to income taxes. Today, windfalls are classified as financing activities. Also, this will affect the dilutive effects in earnings per share, as there will no longer be excess tax benefits recognized in additional paid in capital. Today those excess tax benefits are included in assumed proceeds from applying the treasury stock method when computing diluted EPS. Under the amended guidance, companies will be able to make an accounting policy election to either

(1)

continue to estimate forfeitures or

(2)

account for forfeitures as they occur. This updated guidance is effective for annual and interim periods beginning after 

December

15,

2016.

 Early adoption is permitted. The Company is currently evaluating the potential impact, if any, of the adoption of this update on its consolidated financial statements, however, any impact is not expected to be material.

Leases

In

February

2016,

the FASB issued ASU

2016

-

02,

Leases, Topic

842.

The amendment in this Update introduce a number of changes and simplifications from previous guidance, primarily the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The Update retains the distinction between finance leases and operating leases and the classification criteria between the

two

types remain substantially similar. Also, lessor accounting remains largely unchanged from previous guidance, however, key aspects in the Update were aligned with the revenue recognition guidance in Topic

606.

Additionally, the Update defines a lease as a contract, or part of a contract, that conveys the right to control the use of identified asset for a period of time in exchange for considerations. Control over the use of the identified means that the customer has both (a) the right to obtain substantially all of the economic benefits from the use of the asset and (b) the right to direct the use of the asset. The amendments in this update are effective for annual reporting periods beginning after

December

15,

2018,

including interim periods within those reporting periods. Early adoption is permitted. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements.

Recognition and Measurement of Financial Assets and Financial Liabilities

In

January

2016,

the FASB issued ASU

2016

-

01,

Recognition and Measurement of Financial Assets and Financial Liabilities. The update primarily requires that an entity should present separately, in other comprehensive income, the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk if the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. The application of this update should be by means of cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The amendments in this update are effective for financial statements issued for fiscal years beginning after

December

15,

2017,

and interim periods within those fiscal years. Early adoption is permitted as of the beginning of the fiscal year of adoption. The Company is currently evaluating the potential impact, if any, of the adoption of this update on its consolidated financial statements.

Simplifying the Measurement of Inventory

In

July

2015,

the FASB issued ASU

2015

-

11,

Simplifying the Measurement of Inventory, Topic

330.

The update contains no amendments to disclosure requirements, but replaces the concept of

‘lower of cost or market’ with that of ‘lower of cost and net realizable value’. The amendments in this update are effective for annual reporting periods beginning after

December

15,

2016,

including interim periods within those reporting periods. The amendments should be applied prospectively with early adoption permitted. The Company estimates that the potential impact, if any, of the adoption of this update on its consolidated financial statements is immaterial.

Revenues from Contracts with Customers

In

May

2014,

the FASB issued ASU

2014

-

09,

Revenues from Contracts with Customers, Topic

606,

which was a joint project of the FASB and the International Accounting Standards Board to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The update provides that an entity should recognize revenue in connection with the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Specifically, an entity is required to apply each of the following steps:

(1)

identify the contract(s) with the customer;

(2)

identify the performance obligations in the contracts;

(3)

determine the transaction price;

(4)

allocate the transaction price to the performance obligation in the contract; and

(5)

recognize revenue when (or as) the entity satisfies a performance obligation. ASU

2014

-

09

also prescribes additional financial presentations and disclosures. The amendments in this update are effective for annual reporting periods beginning after

December

15,

2017,

including interim periods within those reporting periods. Early adoption is permitted no earlier than

2017

for calendar fiscal year entities. The Company expects the adoption of this standard to have an immaterial impact, if any, on its Electricity segment as it accounts for its PPA

’s under ASC

840,

Leases. The Company still evaluates the potential impact of the adoption of the standard on its Product segment, however, it believes that such impact, if any, will be immaterial.

In

March

2016,

the FASB issued ASU

2016

-

08,

Principal versus Agent Considerations. The amendment in this Update do not change the core principal of the guidance and are intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations. When another entity is involved in providing goods or services to a customer, an entity is required to determine if the nature of its promise is to provide the specific good or service itself (that is, the entity is a principal) or to arrange for that good or service to be provided by the other party (that is, the entity is an agent). The guidance includes indicators to assist an entity in determining whether it acts as a principal or agent in a specified transaction. The amendments in this update are effective for annual reporting periods beginning after

December

15,

2017,

including interim periods within those reporting periods. Early adoption is permitted no earlier than

2017

for calendar fiscal year entities. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements,

however, it believes that any such impact, if any, will be immaterial.

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Note 1 - Business and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Schedule Of Estimated Useful Lives [Table Text Block]

Buildings (in years)		25
Leasehold improvements (in years)	15	-	20
Machinery and equipment — manufacturing and drilling (in years)		10
Machinery and equipment — computers (in years)	3	-	5
Office equipment — furniture and fixtures (in years)	5	-	15
Office equipment — other (in years)	5	-	10
Automobiles (in years)	5	-	7

Schedule of Weighted Average Number of Shares [Table Text Block]

	Year Ended December 31,
	2016		2015		2014
	(In thousands)
Weighted average number of shares used in computation of basic earnings per share		49,469		48,562		45,508
Add:
Additional shares from the assumed exercise of employee stock options		671		625		351
Weighted average number of shares used in computation of diluted earnings per share		50,140		49,187		45,859

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Note 4 - Inventories (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Schedule of Inventory, Current [Table Text Block]

	December 31,
	2016		2015
	(Dollars in thousands)
Raw materials and purchased parts for assembly	$	5,429	$	8,819
Self-manufactured assembly parts and finished products		6,571		9,255
Total	$	12,000	$	18,074

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Note 5 - Cost and Estimated Earnings on Uncompleted Contracts (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Cost And Estimated Earnings On Uncompleted Contracts [Table Text Block]

	December 31,
	2016			2015
	(Dollars in thousands)
Costs and estimated earnings incurred on uncompleted contracts	$	402,357		$	279,176
Less billings to date		(381,789	)		(287,948	)
Total	$	20,568		$	(8,772	)

Cost And Estimated Earnings On Uncompleted Contracts Included In Consolidated Balance Sheets [Table Text Block]

	December 31,
	2016			2015
	(Dollars in thousands)
Costs and estimated earnings in excess of billings on uncompleted contracts	$	52,198		$	25,120
Billings in excess of costs and estimated earnings on uncompleted contracts		(31,630	)		(33,892	)
Total	$	20,568		$	(8,772	)

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Note 6 - Accumulated Loss of Unconsolidated Company in Excess of Investment (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Equity Method Investments [Table Text Block]

	December 31,
	2016			2015
	(Dollars in thousands)
Sarulla	$	(11,081	)	$	(8,100	)

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Note 7 - Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Schedule of Variable Interest Entities [Table Text Block]

	December 31, 2016
	Project Debt		PPAs
	(Dollars in thousands)
Assets:
Restricted cash and cash equivalents	$	34,262	$	—
Other current assets		157,351		7,482
Property, plant and equipment, net		1,305,254		177,970
Construction-in-process		48,128		72,725
Other long-term assets		24,802		—
Total assets	$	1,569,797	$	258,177
Liabilities:
Accounts payable and accrued expenses	$	10,900	$	3,992
Long-term debt		668,815		—
Other long-term liabilities		126,879		5,779
Total liabilities	$	806,594	$	9,771

	December 31, 2015
	Project Debt		PPAs
	(Dollars in thousands)
Assets:
Restricted cash, cash equivalents and marketable securities	$	49,503	$	—
Other current assets		114,500		4,044
Property, plant and equipment, net		1,310,027		171,231
Construction-in-process		127,825		1,340
Other long-term assets		44,279		(1	)
Total assets	$	1,646,134	$	176,614
Liabilities:
Accounts payable and accrued expenses	$	11,404	$	2,931
Long-term debt		648,028		—
Other long-term liabilities		78,843		5,358
Total liabilities	$	738,275	$	8,289

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Note 8 - Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Fair Value, by Balance Sheet Grouping [Table Text Block]

				December 31, 2016
				Fair Value
	Carrying Value at December 31, 2016			Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets:
Current assets:
Cash equivalents (including restricted cash accounts)	$	14,922		$	14,922		$	14,922	$	—		$	—
Derivatives:
Contingent receivable (1)		1,443			1,443			—		—			1,443
Liabilities:
Current liabilities:
Derivatives:
Contingent payables (1)		(11,581	)		(11,581	)		—		—			(11,581	)
Warrants (1)		(3,429	)		(3,429	)							(3,429	)
Currency forward contracts (2)		(481	)		(481	)		—		(481	)		—
	$	874		$	874		$	14,922	$	(481	)	$	(13,567	)

				December 31, 2015
				Fair Value
	Carrying Value at December 31, 2015			Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	31,428		$	31,428		$	31,428	$	—		$	—
Derivatives:
Currency forward contracts (2)		7			7			—		7			—
Liabilities:
Current liabilities:
Derivatives:
Currency forward contracts (2)		(169	)		(169	)		—		(169	)		—
	$	31,266		$	31,266		$	31,428	$	(162	)	$	—

Derivative Instruments, Gain (Loss) [Table Text Block]

		Amount of recognized gain (loss)
Derivatives not designated as hedging instruments	Location of recognized gain (loss)	2016			2015			2014
		(Dollars in thousands)
Call options on natural gas price	Derivatives and foreign currency transaction gain (losses)	$	(1,340	)	$	—		$	—
Call and put options on oil price	Derivatives and foreign currency transaction gain (losses)		(1,313	)		—			—
Swap transaction on oil price	Electricity revenues		—			—			2,728
Swap transactions on natural gas price	Electricity revenues		—			1,158			2,996
Contingent considerations	Derivatives and foreign currency transaction gain (losses)		(1,527	)		—			—
Currency forward contracts	Derivatives and foreign currency transaction gain (losses)		238			(1,206	)		(4,949	)
		$	(3,942	)	$	(48	)	$	775

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]

	Fair Value				Carrying Amount
	2016		2015		2016		2015
	(Dollars in millions)				(Dollars in millions)
Olkaria III Loan - DEG	$	16.3	$	24.2	$	15.8	$	23.7
Olkaria III Loan - OPIC		253.4		262.6		246.6		264.6
Olkaria IV Loan - DEG 2		50.9		—		50.0		—
Amatitlan Loan		37.3		41.7		36.8		40.3
Senior Secured Notes:
Ormat Funding Corp. ("OFC")	17.0			30.0		17.0		30.0
OrCal Geothermal Inc. ("OrCal")		37.4		43.8		35.2		43.3
OFC 2 LLC ("OFC 2")		249.0		231.1		247.2		262.0
Don A. Campbell 1 ("DAC1")		88.9		—		92.4		—
Senior Unsecured Bonds		200.1		264.5		204.3		250.0
Other long-term debt		10.4		6.7		11.2		6.7

Fair Value, Liabilities Measured on Recurring and Nonrecurring Basis [Table Text Block]

	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III - DEG	$	—	$	—	$	16.3	$	16.3
Olkaria III - OPIC		—		—		253.4		253.4
Olkaria IV - DEG 2		—		—		50.9		50.9
Amatitlan loan		—		37.3		—		37.3
Senior Secured Notes:
OFC		—		17.0		—		17.0
OrCal		—		—		37.4		37.4
OFC 2		—		—		249.0		249.0
Don A. Campbell 1 ("DAC1")		—		—		88.9		88.9
Senior unsecured bonds		—		—		200.1		200.1
Other long-term debt		—		3.3		7.1		10.4
Deposits		14.4		—		—		14.4

	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III Loan - DEG	$	—	$	—	$	24.2	$	24.2
Olkaria III Loan - OPIC		—		—		262.6		262.6
Amatitlan Loan		—		41.7		—		41.7
Senior Secured Notes:
OFC		—		30.0		—		30.0
OrCal		—		—		43.8		43.8
OFC 2		—		—		231.1		231.1
Senior unsecured bonds		—		—		264.5		264.5
Other long-term debt		—		6.7		—		6.7
Deposits		15.9		—		—		15.9

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Note 9 - Property, Plant and Equipment and Construction-in-process (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Property, Plant and Equipment [Table Text Block]

	December 31,
	2016			2015
	(Dollars in thousands)
Land owned by the Company where the geothermal resource is located	$	31,904		$	31,465
Leasehold improvements		3,848			3,691
Machinery and equipment		152,821			133,457
Land, buildings and office equipment		28,634			29,247
Automobiles		11,161			7,782
Geothermal and recovered energy generation power plants, including geothermal wells and exploration and resource development costs:
United States of America, net of cash grants and impairment charges		1,658,195			1,637,081
Foreign countries		541,626			494,105
Asset retirement cost		8,669			7,961
		2,436,858			2,344,789
Less accumulated depreciation		(880,480	)		(785,454	)
Property, plant and equipment, net	$	1,556,378		$	1,559,335

Construction In Progress [Table Text Block]

	December 31,
	2016		2015
	(Dollars in thousands)
Projects under exploration and development:
Up-front bonus lease costs	$	17,385	$	26,491
Exploration and development costs		36,359		35,726
Interest capitalized		703		703
		54,447		62,920
Projects under construction:
Up-front bonus lease costs		37,713		27,473
Drilling and construction costs		202,211		150,467
Interest capitalized		12,338		7,975
		252,262		185,915
Total	$	306,709	$	248,835

Rollforward Of Construction In Process [Table Text Block]

	Projects under Exploration and Development
	Up-front Bonus Lease Costs			Exploration and Development Costs			Interest Capitalized			Total
	(Dollars in thousands)
Balance at December 31, 2013	$	30,141		$	38,220		$	1,278		$	69,639
Cost incurred during the year		—			19,231			—			19,231
Write off of unsuccessful exploration costs		(3,523	)		(11,474	)		(442	)		(15,439	)
Balance at December 31, 2014		26,618			45,977			836			73,431
Cost incurred during the year		37			10,104			869			11,010
Write off of unsuccessful exploration costs		(164	)		(1,415	)		—			(1,579	)
Transfer of projects under exploration and development to projects under construction		—			(18,940	)		(1,002	)		(19,942	)
Balance at December 31, 2015		26,491			35,726			703			62,920
Cost incurred during the year		1,514			25,165			—			26,679
Write off of unsuccessful exploration costs		(380	)		(2,637	)		—			(3,017	)
Transfer of projects under exploration and development to projects under construction		(10,240	)		(21,895	)		—			(32,135	)
Balance at December 31, 2016	$	17,385		$	36,359		$	703		$	54,447

	Projects under Construction
	Up-front Bonus Lease Costs		Drilling and Construction Costs			Interest Capitalized			Total
	(Dollars in thousands)
Balance at December 31, 2013	$	27,473	$	184,766		$	6,948		$	219,187
Cost incurred during the year		—		132,597			3,206			135,803
Transfer of completed projects to property, plant and equipment		—		(105,126	)		(970	)		(106,096	)
Sale of property, plant and equipment		—		(24,692	)		(911	)		(25,603	)
Balance at December 31, 2014		27,473		187,545			8,273			223,291
Cost incurred during the year		—		140,977			3,556			144,533
Transfer of exploration and development projects to projects under construction		—		18,940			1,002			19,942
Transfer of completed projects to property, plant and equipment		—		(196,995	)		(4,856	)		(201,851	)
Sale of property, plant and equipment		—		—			—			—
Balance at December 31, 2015		27,473		150,467			7,975			185,915
Cost incurred during the year		—		116,247			6,510			122,757
Transfer of exploration and development projects to projects under construction		10,240		21,895			—			32,135
Transafer of completed projects to property, plant and equipment		—		(86,398	)		(2,147	)		(88,545	)
Balance at December 31, 2016	$	37,713	$	202,211		$	12,338		$	252,262

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Note 10 - Intangible Assets and Goodwill (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]

	(Dollars in thousands)
Year ending December 31:
2017	$	5,042
2018		4,912
2019		4,839
2020		4,522
2021		4,522
Thereafter		28,916
Total	$	52,753

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Note 11 - Accounts Payable and Accrued Expenses (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Schedule of Accounts Payable and Accrued Liabilities [Table Text Block]

	December 31,
	2016		2015
	(Dollars in thousands)
Trade payables	$	48,309	$	41,364
Salaries and other payroll costs		17,977		14,671
Customer advances		576		2,533
Accrued interest		3,524		8,252
Income tax payable		8,824		11,353
Property tax payable		1,884		3,609
Scheduling and transmission		964		1,547
Royalty accrual		1,639		1,818
Other		7,953		6,808
Total	$	91,650	$	91,955

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Note 12 - Long-term Debt and Credit Agreements (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Schedule of Long-term Debt Instruments [Table Text Block]

	December 31,
	2016			2015
	(Dollars in thousands)
Limited and non-recourse agreements:
Loans:
Non-recourse:
Other loans	$	6,368		$	-
Limited recourse:
Loan agreement with OPIC (the Olkaria III power plant)		246,630			264,624
Loan agreement with Banco Industrial S.A. and Westrust Bank (International) Limited		36,750			40,250
Senior Secured Notes:
Non-recourse:
Ormat Funding Corp. ("OFC")		17,026			29,968
OrCal Geothermal Inc. ("OrCal")		35,181			43,332
Don A. Campbell 1 ("DAC1")		92,361
Limited recourse:
OFC 2 LLC ("OFC 2")		247,232			261,959
		681,548			640,133
Less current portion		(53,729	)		(51,425	)
Non current portion	$	627,819		$	588,708
Full recourse agreements:
Senior unsecured bonds	$	204,332		$	249,981
Loans from institutional investors		3,333			6,667
Loan agreements with DEG (the Olkaria III and IV power plants)		65,789			23,684
Loan from a commercial bank		1,529			-
Revolving credit lines with banks		-			-
		274,983			280,332
Less current portion		(12,242	)		(11,229	)
Non current portion	$	262,741		$	269,103

Schedule of Maturities of Long-term Debt [Table Text Block]

	(Dollars in thousands)
Year ending December 31:
2017	$	65,971
2018		64,805
2019		59,146
2020		126,870
2021		46,579
Thereafter		593,161
Total	$	956,532

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Note 13 - Puna Power Plant Lease Transactions (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

	(Dollars in thousands)
Year ending December 31:
2017	$	8,747
2018		8,944
2019		6,018
2020		2,450
2021		1,723
Thereafter		2,740
Total	$	30,622

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Note 15 - Asset Retirement Obligation (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Schedule of Asset Retirement Obligations [Table Text Block]

	Year Ended December 31,
	2016		2015
	(Dollars in thousands)
Balance at beginning of year	$	20,856	$	19,142
Revision in estimated cash flows		303		(681	)
Liabilities incurred		540		859
Accretion expense		1,649		1,536
Balance at end of year	$	23,348	$	20,856

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Note 16 - Stock-based Compensation (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Table Text Block]

	Year Ended December 31,
	2016		2015		2014
	(Dollars in thousands, except per share data)
Cost of revenues	$	2,400	$	1,753	$	3,076
Selling and marketing expenses		247		123		261
General and administrative expenses		2,510		2,079		2,234
Total stock-based compensation expense		5,157		3,955		5,571
Tax effect on stock-based compensation expense		617		440		836
Net effect of stock-based compensation expense	$	4,540	$	3,515	$	4,735

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]

	Year Ended December 31,
	2016			2015			2014
For stock options issued by the Company:
Risk-free interest rates		1.3	%		1.4	%		1.7	%
Expected lives (in years)		4.5			4.0			5.1
Dividend yield		1.1	%		0.7	%		0.9	%
Expected volatility		30.7	%		29.2	%		35.1	%
Forfeiture rate (weighted average)		8.4	%		0	%		0	%

Schedule of Share-based Compensation, Stock Options and Stock Appreciation Rights Award Activity [Table Text Block]

	Year Ended December 31,
	2016					2015					2014
	Shares (in thousands)			Weighted Average Exercise Price		Shares (in thousands)			Weighted Average Exercise Price		Shares (in thousands)			Weighted Average Exercise Price
Outstanding at beginning of year		2,438		$	25.38		4,477		$	27.48		4,710		$	28.23
Granted, at fair value:
Stock Options		1,155			43.01		45			38.24		485			29.05
SARs*		—			—		—			—		—			—
Exercised		(967	)		25.33		(1,589	)		26.77		(243	)		24.10
Forfeited		(57	)		24.12		(125	)		27.33		(116	)		23.20
Expired		(4	)		26.84		(370	)		45.78		(359	)		42.70
Outstanding at end of year		2,565			33.36		2,438			25.38		4,477			27.48
Options and SARs exercisable at end of year		557			25.22		858			26.75		2,106			31.25
Weighted-average fair value of options and SARs granted during the year				$	11.61				$	8.68				$	9.00

Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, by Exercise Price Range [Table Text Block]

		Options Outstanding						Options Exercisable
Exercise Price		Number of Stock-based Awards Outstanding		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value		Number of Stock-based Awards Exercisable		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value
$	18.56		15		2.8	$	526		15		2.8	$	526
	19.69		15		2.6		509		15		2.6		509
	20.13		108		2.3		3,608		108		2.3		3,608
	20.54		53		2.3		1,761		28		2.3		934
	23.34		635		2.4		19,226		140		2.4		4,247
	24.57		9		2.1		269		1		2.1		33
	25.65		68		1.3		1,905		68		1.3		1,905
	26.70		15		3.8		404		15		3.8		404
	28.23		30		4.8		762		30		4.8		762
	29.52		400		3.6		9,640		75		3.6		1,807
	29.95		17		0.3		400		17		0.3		400
	35.15		15		6.1		277		-		-		-
	38.24		45		5.8		692		45		5.8		692
	42.87		1,080		5.5		11,610		-		-		-
	47.46		60		6.9		370		-		-		-
			2,565		4.1	$	51,959		557		2.7	$	15,827

		Options Outstanding						Options Exercisable
Exercise Price		Number of Stock-based Awards Outstanding		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value		Number of Stock-based Awards Exercisable		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value
$	18.56		15		3.8	$	269		15		3.8	$	269
	19.69		15		3.6		252		15		3.6		252
	20.13		326		3.3		5,327		69		3.3		1,135
	20.54		100		3.3		1,593		50		3.3		797
	23.34		938		3.4		12,315		126		3.4		1,655
	24.57		33		3.1		387		16		3.1		193
	25.65		135		2.3		1,462		135		2.3		1,462
	26.70		45		4.8		440		45		4.8		440
	26.84		64		0.2		618		64		0.2		618
	28.19		15		1.8		124		15		1.8		124
	28.23		45		5.8		371		45		5.8		371
	29.21		3		1.3		22		3		1.3		22
	29.52		400		4.6		2,780		-		-		-
	29.95		148		1.3		963		148		1.3		963
	34.13		96		0.3		225		96		0.3		225
	38.24		15		6.8		-		-		-		-
	38.50		15		0.8		-		15		0.8		-
			2,438		3.3	$	27,148		857		2.4	$	8,526

Chief Financial Officer [Member]

Notes Tables

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]

Risk-free interest rates	0.81	%
Expected life (in years)	3.375
Dividend yield	0.80	%
Expected volatility	33.50	%
Forfeiture rate	0.00	%

	Grant of options to purchase 300,000 shares of common stock			Grant of options to purchase 100,000 shares of common stock
Risk-free interest rates		2.36	%		1.64	%
Expected life (in years)		7.25			4.75
Dividend yield		0.90	%		0.90	%
Expected volatility		42.80	%		33.10	%

Risk-free interest rates	1.30	%
Expected life (in years)	4.0
Dividend yield	0.70	%
Expected volatility	32.40	%
Forfeiture rate	0.00	%

Risk-free interest rates	1.35	%
Expected life (in years)	4.0
Dividend yield	0.70	%
Expected volatility	29.20	%
Forfeiture rate	0.00	%

Stock Appreciation Rights (SARs) [Member]

Notes Tables

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]

Risk-free interest rate	1.29	%
Expected life (in years)	6
Dividend yield	1.14
Expected volatility	30.7	%
Forfeiture rate:
Senior management	0.0	%
Other employees	10.5	%
Sub-Optimal Exercise Factor:
Senior management	2.5
Other employees	2.0

Risk-free interest rate	1.65	%
Expected life (in years)	7
Dividend yield	1.1
Expected volatility	30.6	%
Forfeiture rate:	0.0	%
Sub-Optimal Exercise Factor:	2.5

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Note 18 - Interest Expense, Net (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Schedule of Other Nonoperating Expense, by Component [Table Text Block]

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Interest related to sale of tax benefits	$	9,349		$	9,620		$	12,413
Interest expense		61,327			67,032			75,447
Less — amount capitalized		(3,287	)		(4,075	)		(3,206	)
	$	67,389		$	72,577		$	84,654

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Note 19 - Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Schedule of Income before Income Tax, Domestic and Foreign [Table Text Block]

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
U.S	$	(7,109	)	$	(236	)	$	(2,623	)
Non-U.S. (foreign)		148,197			113,835			88,459
	$	141,088		$	113,599		$	85,836

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Current:
Federal	$	—		$	51		$	—
State		(276	)		252			490
Foreign		14,040			19,175			13,983
	$	13,764		$	19,478		$	14,473
Deferred:
Foreign		18,073			(34,736	)		13,135
		18,073			(34,736	)		13,135
	$	31,837		$	(15,258	)	$	27,608

Components Of Deferred Income Tax Expense Benefit [Table Text Block]

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Other deferred tax expense (exclusive of the effect of other components listed below)	$	(1,105	)	$	541		$	(18,424	)
Usage (benefit) of operating loss carryforwards - U.S.		(14,072	)		(30,596	)		7,764
Change in valuation allowance		16,411			(14,324	)		3,526
Change in foreign valuation allowance		—			(49,701	)		—
Change in foreign income tax		18,073			14,965			13,135
Change in lease transaction		—			(452	)		2,136
Change in tax monetization transaction		48,000			16,386			5,184
Change in depreciation		(55,462	)		28,370			9,431
Change in intangible drilling costs		10,227			10,335			(9,706	)
Change in production tax credits and alternative minimum tax credit		(11,659	)		610			89
Basis difference in partnership interests		7,660			(10,870	)		—
	$	18,073		$	(34,736	)	$	13,135

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

	Year Ended December 31,
	2016			2015			2014
U.S. federal statutory tax rate		35.0	%		35.0	%		35.0	%
Valuation allowance - U.S.		11.1			(1.4	)		(1.7	)
Valuation allowance - foreign		-			(43.8	)
Tax monetization		-			-			2.5
State income tax, net of federal benefit		(0.2	)		0.6			(0.7	)
Effect of foreign income tax, net		(14.1	)		(5.1	)		(4.9	)
Production tax credits		(8.3	)		(0.1	)		0.9
Subpart F income		0.3			1.3			1.4
Depletion		-			-			(1.1	)
Other, net		(1.3	)		-			0.8
Effective tax rate		22.5	%		(13.5)	%		32.2	%

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

	December 31,
	2016			2015
	(Dollars in thousands)
Deferred tax assets (liabilities):
Net foreign deferred taxes, primarily depreciation	$	(35,382	)	$	(32,654	)
Depreciation		148,419			87,943
Intangible drilling costs		(112,762	)		(102,013	)
Net capital loss carryforward - U.S.		117,924			103,850
Tax monetization transaction		(105,789	)		(80,478	)
Investment tax credits		1,341			1,341
Production tax credits		82,451			70,792
Stock options amortization		3,241			3,467
Basis difference in partnership interest		(24,462	)		(16,801	)
Accrued liabilities and other		(752	)		2,435
		74,229			37,882
Less - valuation allowance		(109,611	)		(70,536	)
Total	$	(35,382	)	$	(32,654	)

Summary of Valuation Allowance [Table Text Block]

	Year Ended December 31,
	2016		2015			2014
	(Dollars in thousands)
Balance at beginning of the year	$	70,536	$	111,280		$	114,806
Additions to (release of) valuation allowance		39,075		(40,744	)		(3,526	)
Balance at end of the year	$	109,611	$	70,536		$	111,280

Schedule Of Deferred Taxes Classified In Balance Sheet [Table Text Block]

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Current deferred tax assets	$	—		$	—		$	251
Current deferred tax liabilities		—			—			(975	)
Non-current deferred tax liabilities		(35,382	)		(32,654	)		(66,219	)
	$	(35,382	)	$	(32,654	)	$	(66,943	)

Summary of Income Tax Contingencies [Table Text Block]

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Balance at beginning of year	$	10,385		$	7,511		$	4,950
Additions based on tax positions taken in prior years		675			(198	)		230
Additions based on tax positions taken in the current year		1,059			4,386			2,980
Reduction based on tax positions taken in prior years		(6,381	)		(1,314	)		(649	)
Balance at end of year	$	5,738		$	10,385		$	7,511

Summary of Income Tax Examinations [Table Text Block]

Israel	2015	—	2016
Kenya	2001	—	2016
Guatemala	2010	—	2016
Philippines	2010	—	2016
New Zealand	2011	—	2016

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Note 20 - Business Segments (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Schedule of Segment Reporting Information, by Segment [Table Text Block]

	Electricity		Product		Consolidated
	(Dollars in thousands)
Year Ended December 31, 2016:
Net revenues from external customers	$	436,292	$	226,299	$	662,591
Intersegment revenues		—		56,075		56,075
Depreciation and amortization expense		102,698		3,279		105,977
Operating income		126,828		75,054		201,882
Segment assets at period end		2,204,444		257,125		2,461,569
Expenditures for long-lived assets		147,211		4,719		151,930
Year Ended December 31, 2015:
Net revenues from external customers	$	375,920	$	218,724	$	594,644
Intersegment revenues		—		48,559		48,559
Depreciation and amortization expense		103,892		3,314		107,206
Operating income		99,345		64,716		164,061
Segment assets at period end		2,044,346		229,636		2,273,982
Expenditures for long-lived assets		149,666		2,784		152,450
Year Ended December 31, 2014 :
Net revenues from external customers	$	382,301	$	177,223	$	559,524
Intersegment revenues		—		44,718		44,718
Depreciation and amortization expense		97,826		2,973		100,799
Operating income		90,401		53,089		143,490
Segment assets at period end		1,963,486		158,070		2,121,556
Expenditures for long-lived assets		155,323		3,458		158,781

Reconciliation of Operating Profit (Loss) from Segments to Consolidated [Table Text Block]

	Year Ended December 31,
	2016			2015			2014
	(Dollars in thousands)
Revenues:
Total segment revenues	$	662,591		$	594,644		$	559,524
Intersegment revenues		56,075			48,559			44,718
Elimination of intersegment revenues		(56,075	)		(48,559	)		(44,718	)
Total consolidated revenues	$	662,591		$	594,644		$	559,524
Operating income:
Operating income	$	201,882		$	164,061		$	143,490
Interest income		971			297			312
Interest expense, net		(67,389	)		(72,577	)		(84,654	)
Foreign currency translation and transaction losses		(5,534	)		(1,622	)		(5,839	)
Income attributable to sale of equity interest		16,503			25,431			24,143
Gain from sale of property, plant and equipment		—			—			7,628
Other non-operating income, net		(5,345	)		(1,991	)		756
Total consolidated income before income taxes and equity in income of investees	$	141,088		$	113,599		$	85,836

Schedule of Revenue from External Customers and Long-Lived Assets, by Geographical Areas [Table Text Block]

	Year Ended December 31,
	2016		2015		2014
	(Dollars in thousands)
Revenues from external customers attributable to: (1)
United States	$	307,025	$	286,509	$	293,710
Indonesia		100,856		93,191		38,174
Kenya		109,270		86,545		86,074
Turkey		46,270		57,356		86,340
Chile		58,032		34,478		—
Guatemala		30,086		27,897		28,439
Other foreign countries		11,052		8,668		26,787
Consolidated total	$	662,591	$	594,644	$	559,524

Schedule of Disclosure on Geographic Areas, Long-Lived Assets in Individual Foreign Countries by Country [Table Text Block]

	Year Ended December 31,
	2016		2015		2014
	(Dollars in thousands)
Long-lived assets (primarily power plants and related assets) located in:
United States	$	1,414,523	$	1,374,465	$	1,369,136
Kenya		327,157		375,257		330,200
Other foreign countries		199,559		107,407		90,735
Consolidated total	$	1,941,239	$	1,857,129	$	1,790,071

Schedule of Revenue by Major Customers by Reporting Segments [Table Text Block]

	Year Ended December 31,
	2016				2015				2014
	Revenues		%		Revenues		%		Revenues		%
	(Dollars in thousands)				(Dollars in thousands)				(Dollars in thousands)
Southern California Edison (1)	$	33,552		5.1	$	56,026		9.4	$	75,803		13.5
Southern California Public Power Authority  (1)		67,566		10.2		30,947		5.2		21,799		3.9
Sierra Pacific Power Company and Nevada Power Company (1)(2)		127,226		19.2		115,876		19.5		92,580		16.5
Hyundai (3)		100,856		15.2		93,131		15.7		38,174		6.8
KPLC (1)		109,270		16.5		86,545		14.6		86,074		15.4

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Note 21 - Transactions with Related Entities (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Schedule of Related Party Transactions [Table Text Block]

	Year Ended December 31,
	2016		2015		2014
	(Dollars in thousands)
Property rental fee expense paid to the Parent	$	—	$	303	$	1,821
Corporate financial, administrative, executive services, and research and development services provided to the Parent	$	—	$	148	$	148
Services rendered by an indirect shareholder of the Parent	$	—	$	15	$	51

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Note 22 - Employee Benefit Plan (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Schedule of Expected Benefit Payments [Table Text Block]

			( Dollars in thousands )
Year ending December 31 :
201 7			$	1,867
201 8				2,497
201 9				1,655
20 20				1,119
20 21				1,400
20 22	-	2026		5,141
			$	13,679

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Note 24 - Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Notes Tables

Quarterly Financial Information [Table Text Block]

	Three Months Ended
	Mar. 31, 2015			June 30, 2015			Sept. 30, 2015			Dec. 31, 2015			Mar. 31, 2016			June 30, 2016			Sept. 30, 2016			Dec. 31, 2016
	(Dollars in thousands, except per share amounts)
Revenues:
Electricity	$	89,953		$	90,926		$	97,245		$	97,796		$	107,868		$	104,001		$	109,795		$	114,628
Product		30,278			49,561			65,607			73,278			43,726			55,860			74,822			51,891
Total revenues		120,231			140,487			162,852			171,074			151,594			159,861			184,617			166,519
Cost of revenues:
Electricity		55,581			62,522			61,501			63,008			63,686			62,243			66,481			69,163
Product		20,625			27,182			42,019			43,927			24,035			31,822			43,647			30,719
Total cost of revenues		76,206			89,704			103,520			106,935			87,721			94,065			110,128			99,882
Gross profit		44,025			50,783			59,332			64,139			63,873			65,796			74,489			66,637
Operating expenses:
Research and development expenses		363			414			335			668			349			595			1,086			732
Selling and marketing expenses		3,433			4,283			4,383			3,978			3,675			3,668			4,793			4,288
General and administrative expenses		10,204			7,443			7,950			9,185			8,749			8,783			19,093			10,085
Write-off of unsuccessful exploration activities		174			--			185			1,220			557			863			1,294			303
Operating income		29,851			38,643			46,479			49,088			50,543			51,887			48,223			51,229
Other income (expense):
Interest income		9			44			53			191			320			245			266			140
Interest expense, net		(17,828	)		(18,859	)		(17,748	)		(18,142	)		(16,023	)		(18,401	)		(17,137	)		(15,828	)
Foreign currency translation and transaction gains (losses)		(1,366	)		(571	)		1,296			(981	)		1,962			(4,332	)		(222	)		(2,942	)
Income attributable to sale of tax benefits		5,552			4,731			8,634			6,514			4,398			4,519			3,463			4,123
Other non-operating income (expense), net		283			(1,675	)		(131	)		(468	)		191			49			(5,546	)		(39	)
Income (loss) from continuing operations, before income taxes and equity in income of investees		16,501			22,313			38,583			36,202			41,391			33,967			29,047			36,683
Income tax benefit (provision)		(5,459	)		(6,056	)		38,211			(11,438	)		(9,509	)		(7,890	)		(11,988	)		(2,450	)
Equity in income (losses) of investees		(775	)		(984	)		(3,133	)		(616	)		(937	)		(1,144	)		(2,653	)		(3,001	)
Net income (loss)		10,267			15,273			73,661			24,148			30,945			24,933			14,406			31,232
Net loss (income) attributable to noncontrolling interest		(235	)		(859	)		(1,522	)		(1,160	)		(1,674	)		(584	)		(2,326	)		(3,002	)
Net income (loss) attributable to the Company's stockholders	$	10,032		$	14,414		$	72,139		$	22,988		$	29,271		$	24,349		$	12,080		$	28,230
Earnings (loss) per share attributable to the Company's stockholders
Basic:
Net income	$	0.21		$	0.29		$	1.47		$	0.47		$	0.60		$	0.49		$	0.24		$	0.57
Diluted:
Net income	$	0.21		$	0.28		$	1.41		$	0.46		$	0.59		$	0.49		$	0.24		$	0.56
Weighted average number of shares used in computation of earnings per share attributable to the Company's stockholders:
Basic		47,244			48,881			49,023			49,074			49,173			49,456			49,599			49,647
Diluted		48,079			50,600			51,113			49,668			49,782			50,137			50,289			50,293

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Note 1 - Business and Significant Accounting Policies (Details Textual) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Dividends, Common Stock, Cash									$ 25,700,000	$ 12,700,000	$ 9,600,000
Common Stock, Dividends, Per Share, Declared									$ 0.52	$ 0.26	$ 0.21
Cash, Cash Equivalents, and Short-term Investments	$ 230,214,000				$ 185,919,000				$ 230,214,000	$ 185,919,000	$ 40,230,000	$ 57,354,000
Accounts Receivable, Net, Current	80,807,000				55,301,000				80,807,000	55,301,000
Interest Costs Capitalized									3,287,000	4,075,000	3,206,000
Exploration Abandonment and Impairment Expense	303,000	$ 1,294,000	$ 863,000	$ 557,000	1,220,000	$ 185,000		$ 174,000	3,017,000	1,579,000	15,439,000
Grants Received to Offset Exploration and Development Costs Incurred									300,000	800,000	1,700,000
Accumulated Amortization, Debt Issuance Costs	31,100,000				37,200,000				31,100,000	37,200,000
Amortization of Debt Issuance Costs									6,900,000	8,800,000	6,500,000
Write off of Deferred Debt Issuance Cost									100,000	500,000	700,000
Deferred Costs, Leasing, Gross	4,200,000								$ 4,200,000
Lease Payment Term									23 years
Interest Expense	15,828,000	17,137,000	18,401,000	16,023,000	18,142,000	17,748,000	18,859,000	17,828,000	$ 67,389,000	72,577,000	84,654,000
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax									12,000	44,000	228,000
Income Tax Expense (Benefit)	2,450,000	$ 11,988,000	$ 7,890,000	$ 9,509,000	11,438,000	$ (38,211,000)	$ 6,056,000	$ 5,459,000	31,837,000	(15,258,000)	27,608,000
Research and Development Arrangement with Federal Government, Customer Funding to Offset Costs Incurred									$ 0	$ 0	$ 600,000
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount									102,793	467,766	3,237,593
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Debt Issuance Costs	17,700,000				19,100,000				$ 17,700,000	$ 19,100,000
Provision for Doubtful Accounts									0
Line-of-credit Arrangements [Member]
Debt Issuance Costs, Line of Credit Arrangements, Net	1,100,000				1,000,000				1,100,000	1,000,000
Reclassification out of Accumulated Other Comprehensive Income [Member]
Interest Expense									(9,000)	(27,000)	$ (141,000)
Income Tax Expense (Benefit)									(3,000)	(17,000)	(87,000)
Puna Geothermal Ventures [Member]
Deferred Costs, Leasing, Gross	4,200,000								$ 4,200,000
Lease Payment Term									23 years
Deferred Costs, Leasing, Accumulated Amortization	2,100,000				2,000,000				$ 2,100,000	2,000,000
Amortization of Deferred Leasing Fees									$ 200,000	$ 200,000	200,000
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Primary Customers [Member]
Concentration Risk, Percentage									60.00%	66.00%
Maximum [Member]
Cash, FDIC Insured Amount	250,000								$ 250,000
Finite-Lived Intangible Asset, Useful Life									25 years
Maximum [Member] | Power Plants [Member]
Property, Plant and Equipment, Useful Life										30 years
Minimum [Member]
Finite-Lived Intangible Asset, Useful Life									13 years
Minimum [Member] | Power Plants [Member]
Property, Plant and Equipment, Useful Life									15 years
UNITED STATES
Cash, Cash Equivalents, and Short-term Investments	72,500,000				19,000,000				$ 72,500,000	$ 19,000,000
Foreign Countries [Member]
Cash, Cash Equivalents, and Short-term Investments	166,200,000				181,000,000				166,200,000	181,000,000
Accounts Receivable, Net, Current	$ 53,300,000				$ 27,800,000				53,300,000	27,800,000
Twilight Site in Oregon [Member]
Exploration Abandonment and Impairment Expense									$ 1,000,000
Wister Site in California [Member]
Exploration Abandonment and Impairment Expense											8,100,000
Mount Spur Site in Alaska [Member]
Exploration Abandonment and Impairment Expense											$ 7,300,000
Maui Site in Hawaii [Member]
Exploration Abandonment and Impairment Expense										$ 1,000,000

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Note 1 - Business and Significant Accounting Policies - Property, Plant, and Equipment Estimated Useful Life (Details)	12 Months Ended
	Dec. 31, 2016
Building [Member]
Property, plant, and equipment estimated useful lives (Year)	25 years
Leasehold Improvements [Member] | Minimum [Member]
Property, plant, and equipment estimated useful lives (Year)	15 years
Leasehold Improvements [Member] | Maximum [Member]
Property, plant, and equipment estimated useful lives (Year)	20 years
Machinery And Equipment - Manufacturing And Drilling [Member]
Property, plant, and equipment estimated useful lives (Year)	10 years
Machinery And Equipment - Computers [Member] | Minimum [Member]
Property, plant, and equipment estimated useful lives (Year)	3 years
Machinery And Equipment - Computers [Member] | Maximum [Member]
Property, plant, and equipment estimated useful lives (Year)	5 years
Furniture and Fixtures [Member] | Minimum [Member]
Property, plant, and equipment estimated useful lives (Year)	5 years
Furniture and Fixtures [Member] | Maximum [Member]
Property, plant, and equipment estimated useful lives (Year)	15 years
Office Equipment - Other [Member] | Minimum [Member]
Property, plant, and equipment estimated useful lives (Year)	5 years
Office Equipment - Other [Member] | Maximum [Member]
Property, plant, and equipment estimated useful lives (Year)	10 years
Automobiles [Member] | Minimum [Member]
Property, plant, and equipment estimated useful lives (Year)	5 years
Automobiles [Member] | Maximum [Member]
Property, plant, and equipment estimated useful lives (Year)	7 years

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Note 1 - Business and Significant Accounting Policies - Shares Used to Calculate Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Weighted average number of shares used in computation of basic earnings per share (in shares)	49,647	49,599	49,456	49,173	49,074	49,023	48,881	47,244	49,469	48,562	45,508
Additional shares from the assumed exercise of employee stock options (in shares)									671	625	351
Weighted average number of shares used in computation of diluted earnings per share (in shares)	50,293	50,289	50,137	49,782	49,668	51,113	50,600	48,079	50,140	49,187	45,859

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Note 2 - Share Exchange Transaction (Details Textual) - USD ($) $ in Millions	Feb. 12, 2015	Dec. 31, 2016	Dec. 31, 2015	Feb. 11, 2015
Common Stock, Shares, Outstanding		49,667,340	49,107,901
Ormat Industries Ltd. [Member]
Percentage of Public Float Before Transition to Noncontrolled Public Company				40.00%
Percentage of Public Float After Transition to Noncontrolled Public Company	76.00%
Share Exchange Shares Granted Per Share	0.2592
Conversion of Stock, Shares Issued	30,200,000
Stock Issued During Period, Shares, New Issues	3,000,000
Common Stock, Shares, Outstanding	48,500,000			45,500,000
Sale of Stock, Consideration Received on Transaction	$ 15.4
Ormat Industries Ltd. [Member] | Shares Issued to Self, Deducted [Member]
Conversion of Stock, Shares Issued	27,200,000
Ormat Industries Ltd. [Member] | Sale of Stock, Other Assets Received [Member]
Sale of Stock, Consideration Received Per Transaction	$ 0.6
Ormat Industries Ltd. [Member] | Sale of Stock, Land and Buildings Received [Member]
Sale of Stock, Consideration Received Per Transaction	12.1
Ormat Industries Ltd. [Member] | Sale of Stock, Liabilities Assumed [Member]
Sale of Stock, Consideration Received Per Transaction	$ 0.5

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Note 3 - Northleaf Transactions and Business Acquisition (Details Textual) $ in Thousands, € in Millions				1 Months Ended		7 Months Ended		12 Months Ended
	Dec. 29, 2016 USD ($) MWh	Nov. 23, 2016 USD ($)	Apr. 30, 2015 USD ($)	Jul. 31, 2016 USD ($) MWh	Jul. 31, 2016 EUR (€) MWh	Jul. 31, 2016 USD ($) MWh	Jul. 31, 2016 EUR (€)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Noncontrolling Interest, Increase from Subsidiary Equity Issuance								$ 44,102	$ 156,635
Payments to Acquire Businesses, Net of Cash Acquired								20,135
Goodwill								6,650
Redeemable Noncontrolling Interest, Equity, Carrying Amount								4,772
Stockholders' Equity Attributable to Noncontrolling Interest								91,582	93,873
Viridity Energy, Inc. [Member]
Power Generated Under Contract | MWh	850
Number of Sites	3,000
Geothermie Bouillante SA (“GB”) [Member]
Expected Power Generating Capacity | MWh				14.75	14.75
Power Utilization | MWh				13	13
Number of Exploration Licenses Owned				2		2
Business Acquisition, Expansion Capacity | MWh				45		45
Business Acquisition, Percentage of Voting Interests Acquired				60.00%		60.00%
Business Combination, Expected Ownership Interest				85.00%		85.00%
Payments to Acquire Businesses, Net of Cash Acquired				$ 20,600
Payments to Acquire Businesses, Additional Amount Subject to Achievement of Agreed upon Production Thresholds						$ 13,400	€ 12.0
Power Purchase Agreements Term						15 years	15 years
Goodwill				7,100		$ 7,100
Redeemable Noncontrolling Interest, Equity, Carrying Amount								5,000
Stockholders' Equity Attributable to Noncontrolling Interest								8,300
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual								8,100
Geothermie Bouillante SA (“GB”) [Member] | Service Agreements [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles				$ 33,000		$ 33,000
Geothermie Bouillante SA (“GB”) [Member] | After Further Invest in Two Years [Member]
Business Combination, Expected Ownership Interest				63.75%		63.75%
Payments to Acquire Additional Interest in Subsidiaries				$ 8,400	€ 7.5
Geothermie Bouillante SA (“GB”) [Member] | Ormat Systems LTD and Caisse des Depots et Consignations (CDC) [Member]
Business Acquisition, Percentage of Voting Interests Acquired				80.00%		80.00%
Business Combination, Co-acquisition, Percentage of Ownership Interest Allocated				75.00%		75.00%
Geothermie Bouillante SA (“GB”) [Member] | Caisse des Depots et Consignations (CDC) [Member]
Business Combination, Co-acquisition, Percentage of Ownership Interest Allocated				25.00%		25.00%
Viridity Energy, Inc. [Member]
Business Combination, Consideration Transferred	$ 35,000
Additional Paid-in Capital [Member]
Noncontrolling Interest, Increase from Subsidiary Equity Issuance								7,834	71,165
Noncontrolling Interest [Member]
Noncontrolling Interest, Increase from Subsidiary Equity Issuance								$ 36,268	$ 85,470
ORPD LLC [Member] | Northleaf Transactions [Member]
Percentage of Equity Interest Sold			36.75%
Number of Power Plant Units Across Recovered Energy Generation Assets			9
Recovered Energy Generation Assets			3
Sale of Stock, Consideration Received Per Transaction			$ 162,300
Sale of Stock, Consideration Received on Transaction			156,800
Payments of Stock Issuance Costs			5,500
Sale of Stock, Taxable Gain (Loss)			102,100
ORPD LLC [Member] | Northleaf Transactions [Member] | Additional Paid-in Capital [Member]
Noncontrolling Interest, Increase from Subsidiary Equity Issuance			71,300
ORPD LLC [Member] | Northleaf Transactions [Member] | Noncontrolling Interest [Member]
Noncontrolling Interest, Increase from Subsidiary Equity Issuance			$ 85,500
Second Phase of the Don A. Cambell Power Plant [Member] | Northleaf Transactions [Member]
Percentage of Equity Interest Sold		36.75%
Sale of Stock, Consideration Received Per Transaction		$ 44,200
Sale of Stock, Consideration Received on Transaction		44,100
Payments of Stock Issuance Costs		100
Sale of Stock, Taxable Gain (Loss)		21,400
Second Phase of the Don A. Cambell Power Plant [Member] | Northleaf Transactions [Member] | Additional Paid-in Capital [Member]
Noncontrolling Interest, Increase from Subsidiary Equity Issuance		7,800
Second Phase of the Don A. Cambell Power Plant [Member] | Northleaf Transactions [Member] | Noncontrolling Interest [Member]
Noncontrolling Interest, Increase from Subsidiary Equity Issuance		$ 36,300

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Note 4- Inventories - Inventories, Current (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Raw materials and purchased parts for assembly	$ 5,429	$ 8,819
Self-manufactured assembly parts and finished products	6,571	9,255
Total	$ 12,000	$ 18,074

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Note 5 - Cost and Estimated Earnings on Uncompleted Contracts - Cost and Estimated Earnings on Uncompleted Contracts (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Costs and estimated earnings incurred on uncompleted contracts	$ 402,357	$ 279,176
Less billings to date	(381,789)	(287,948)
Total	$ 20,568
Total		$ (8,772)

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Note 5 - Cost and Estimated Earnings on Uncompleted Contracts - Cost and Estimated Earnings on Uncompleted Contracts Included in Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Costs and estimated earnings in excess of billings on uncompleted contracts	$ 52,198	$ 25,120
Billings in excess of costs and estimated earnings on uncompleted contracts	(31,630)	(33,892)
Total	$ 20,568
Total		$ (8,772)

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Note 6 - Accumulated Loss of Unconsolidated Company in Excess of Investment (Details Textual) $ in Thousands		3 Months Ended								12 Months Ended
	Jun. 04, 2014 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2016 USD ($) MWh	Dec. 31, 2016 USD ($)	Dec. 31, 2016 USD ($) Boe	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	May 23, 2014 USD ($)	May 16, 2014 USD ($)	Oct. 31, 2013 USD ($)
Number of Commercial Lenders in Funding Consortium																		6
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax													$ 1,185		$ 1,028	$ (8,112)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest		$ 31,232	$ 14,406	$ 24,933	$ 30,945	$ 24,148	$ 73,661	$ 15,273	$ 10,267				101,516		$ 123,349	$ 55,015
Intersegment Eliminations [Member]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest													$ 12,000
London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument, Basis Spread on Variable Rate															1.00%
Sarulla [Member] | Lenders Consortium [Member]
Senior Notes																		$ 1,170,000
Sarulla [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share		12.75%								12.75%	12.75%	12.75%	12.75%	12.75%
Expected Power Generating Capacity												330		321
Contract Effective Date										April 4, 2013
Power Plant Usage Agreement Term										30 years
Number Of Phases Of Construction											3
Power Utilization | Boe														110
Percentage of Required Production Capacity		80.00%								80.00%	80.00%	80.00%	80.00%	80.00%
Percentage of Required Injection Capacity		85.00%								85.00%	85.00%	85.00%	85.00%	85.00%
Supply Commitment, Remaining Minimum Amount Committed																			$ 255,600
Payments to Acquire Projects													$ 3,600
Sarulla [Member] | Interest Rate Swap [Member]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax													1,200		$ 1,000
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax		$ (5,900)								$ (5,900)	$ (5,900)	$ (5,900)	(5,900)	$ (5,900)
Sarulla [Member] | Interest Rate Swap [Member] | Sarulla Project Company [Member]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax													$ 9,300		$ 8,000
Sarulla [Member] | Lenders Consortium [Member] | Interest Rate Swap [Member]
Proceeds from Issuance of Senior Long-term Debt	$ 50,000
Sarulla [Member] | Lenders Consortium [Member] | Interest Rate Swap [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument, Basis Spread on Variable Rate	3.4565%
Sarulla [Member] | Lenders Consortium [Member] | Subject to Fixed Interest Rate [Member]
Senior Notes																	$ 100,000
Sarulla [Member] | Lenders Consortium [Member] | Subject to Fixed LIBOR Interest Rate [Member]
Senior Notes																	$ 1,070,000
Sarulla [Member] | Lenders Consortium [Member] | Subject to Fixed LIBOR Interest Rate [Member] | Interest Rate Swap [Member]
Senior Notes	$ 960,000

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Note 6 - Accumulated Loss of Unconsolidated Company in Excess of Investment - Unconsolidated Investments Mainly in Power Plants (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Sarulla	$ (11,081)	$ (8,100)
Sarulla [Member]
Sarulla	$ (11,081)	$ (8,100)

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Note 7 - Variable Interest Entities - Assets and Liabilities for the Company's 2015 Variable Interest Entity (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted cash and cash equivalents		$ 34,262	$ 49,503
Property, plant and equipment, net		1,556,378	1,559,335
Construction-in-process		306,709	248,835
Total assets	[1]	2,461,569	2,273,982	$ 2,121,556
Accounts payable and accrued expenses		91,650	91,955
Long-term debt		956,532
Other long-term liabilities		21,294	1,776
Total liabilities		1,286,790	1,190,108
Property, plant and equipment, net		1,556,378	1,559,335
Construction-in-process		306,709	248,835
Variable Interest Entity, Primary Beneficiary [Member] | Project Debt [Member]
Restricted cash and cash equivalents		34,262	49,503
Other current assets		157,351	114,500
Property, plant and equipment, net		1,305,254	1,310,027
Construction-in-process		48,128	127,825
Other long-term assets		24,802	44,279
Total assets		1,569,797	1,646,134
Accounts payable and accrued expenses		10,900	11,404
Long-term debt		668,815	648,028
Other long-term liabilities		126,879	78,843
Total liabilities		806,594	738,275
Property, plant and equipment, net		1,305,254	1,310,027
Construction-in-process		48,128	127,825
Variable Interest Entity, Primary Beneficiary [Member] | Power Purchase Agreements [Member]
Restricted cash and cash equivalents
Other current assets		7,482	4,044
Property, plant and equipment, net		177,970	171,231
Construction-in-process		72,725	1,340
Other long-term assets			(1)
Total assets		258,177	176,614
Accounts payable and accrued expenses		3,992	2,931
Long-term debt
Other long-term liabilities		5,779	5,358
Total liabilities		9,771	8,289
Property, plant and equipment, net		177,970	171,231
Construction-in-process		$ 72,725	$ 1,340

[1] Including unconsolidated investments

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Note 8 - Fair Value of Financial Instruments (Details Textual) BTU in Millions, $ in Millions							1 Months Ended	3 Months Ended	10 Months Ended	11 Months Ended	12 Months Ended
	Feb. 24, 2016 Boe $ / item	Feb. 02, 2016 BTU $ / item	Mar. 14, 2015 $ / BTU	Mar. 06, 2014 BTU $ / BTU	Oct. 16, 2013 MWh BTU £ / item bbl	Sep. 03, 2013 BTU £ / item	Mar. 31, 2016 Boe $ / item	Mar. 31, 2015 BTU	Dec. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Feb. 28, 2016 $ / item
Derivative, Number of Options Rolled							2
Gain (Loss) on Price Risk Derivative Instruments Not Designated as Hedging Instruments | $											$ (2.4)	$ (1.2)	$ (4.9)
Foreign Currency Gain (Loss) [Member]
Gain (Loss) on Price Risk Derivative Instruments Not Designated as Hedging Instruments | $												$ 1.2	$ 5.7
NGI Swap Contract [Member]
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU				2.2	4.2	4.4		2.4
Underlying, Derivative Energy Measure			3,000,000	4,950,000	4,103,000	4,035,000
New York Harbor ULSD Swap Contract [Member]
Underlying, Derivative Energy Measure | £ / item					125.15
Derivative, Nonmonetary Notional Amount, Volume | bbl					275,000
Fluctuation in Energy Rate | MWh					25
Henry Hub Natural Gas Future ("NG") Contracts [Member]
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU		4.1
Derivative, Price Risk Option Strike Price		2
Henry Hub Natural Gas Future ("NG") Contracts [Member] | Call Option [Member]
Proceeds from Derivative Instrument, Investing Activities | $										$ 1.9
Brent Oil Future Contracts [Member]
Derivative, Nonmonetary Notional Amount, Energy Measure | Boe	185,000
Brent Oil Future Contracts [Member] | Minimum [Member]
Derivative, Price Risk Option Strike Price	32.8
Brent Oil Future Contracts [Member] | Maximum [Member]
Derivative, Price Risk Option Strike Price	35.5
Brent Oil Future Contracts [Member] | Call Option [Member]
Proceeds from Derivative Instrument, Investing Activities | $									$ 1.1
Rolled Two Existing Options [Member]
Derivative, Nonmonetary Notional Amount, Energy Measure | Boe							31,800
Rolled Two Existing Options [Member] | Minimum [Member]
Derivative, Price Risk Option Strike Price							41
Rolled Two Existing Options [Member] | Maximum [Member]
Derivative, Price Risk Option Strike Price							42.5
Before Rolling Two Existing Options [Member] | Minimum [Member]
Derivative, Price Risk Option Strike Price														32.8
Before Rolling Two Existing Options [Member] | Maximum [Member]
Derivative, Price Risk Option Strike Price														33.5
Short Risk Reversal Transactions, Rolling Existing Call Option 1 [Member]
Derivative, Nonmonetary Notional Amount, Energy Measure | Boe							16,500
Short Risk Reversal Transactions, Rolling Existing Call Option 1 [Member] | Minimum [Member]
Derivative, Price Risk Option Strike Price							28.5
Short Risk Reversal Transactions, Rolling Existing Call Option 1 [Member] | Maximum [Member]
Derivative, Price Risk Option Strike Price							37.5
Short Risk Reversal Transactions, Rolling Existing Call Option 2 [Member] | Minimum [Member]
Derivative, Price Risk Option Strike Price							28
Short Risk Reversal Transactions, Rolling Existing Call Option 2 [Member] | Maximum [Member]
Derivative, Price Risk Option Strike Price							38.5

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Note 8 - Fair Value of Financial Instruments - Financial Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Reported Value Measurement [Member]
Cash equivalents (including restricted cash accounts)		$ 14,922	$ 31,428
		874	31,266
Reported Value Measurement [Member] | Contingent Receivable [Member]
Derivative Asset, Current	[1]	1,443
Reported Value Measurement [Member] | Currency Forward Contracts [Member]
Derivative Asset, Current	[2]		7
Derivative Liability, Current	[2]	(481)	(169)
Reported Value Measurement [Member] | Contingent Payable [Member]
Derivative Liability, Current	[1]	(11,581)
Reported Value Measurement [Member] | Warrant [Member]
Derivative Liability, Current	[1]	(3,429)
Estimate of Fair Value Measurement [Member]
Cash equivalents (including restricted cash accounts)		14,922	31,428
		874	31,266
Estimate of Fair Value Measurement [Member] | Contingent Receivable [Member]
Derivative Asset, Current	[1]	1,443
Estimate of Fair Value Measurement [Member] | Currency Forward Contracts [Member]
Derivative Asset, Current	[2]		7
Derivative Liability, Current	[2]	(481)	(169)
Estimate of Fair Value Measurement [Member] | Contingent Payable [Member]
Derivative Liability, Current	[1]	(11,581)
Estimate of Fair Value Measurement [Member] | Warrant [Member]
Derivative Liability, Current	[1]	(3,429)
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Cash equivalents (including restricted cash accounts)		14,922	31,428
		14,922	31,428
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member] | Contingent Receivable [Member]
Derivative Asset, Current	[1]
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member] | Currency Forward Contracts [Member]
Derivative Asset, Current	[2]
Derivative Liability, Current	[2]
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member] | Contingent Payable [Member]
Derivative Liability, Current	[1]
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member] | Warrant [Member]
Derivative Liability, Current	[1]
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]
Cash equivalents (including restricted cash accounts)
		(481)	(162)
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member] | Contingent Receivable [Member]
Derivative Asset, Current	[1]
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member] | Currency Forward Contracts [Member]
Derivative Asset, Current	[2]		7
Derivative Liability, Current	[2]	(481)	(169)
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member] | Contingent Payable [Member]
Derivative Liability, Current	[1]
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member] | Warrant [Member]
Derivative Liability, Current	[1]
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member]
Cash equivalents (including restricted cash accounts)
		(13,567)
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member] | Contingent Receivable [Member]
Derivative Asset, Current	[1]	1,443
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member] | Currency Forward Contracts [Member]
Derivative Asset, Current	[2]
Derivative Liability, Current	[2]
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member] | Contingent Payable [Member]
Derivative Liability, Current	[1]	(11,581)
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member] | Warrant [Member]
Derivative Liability, Current	[1]	$ (3,429)

[1] These amounts relate to contingent receivables and payables pertaining to the Guadeloupe power plant purchase transaction, valued primarily based on unobservable inputs and are included within "Prepaid expenses and other" and "Other long-term liabilities" on December 31, 2016 in the consolidated balance sheets with the corresponding gain or loss being recognized within "Derivatives and foreign currency transaction gains (losses)"? in the consolidated statement of operations and comprehensive income.

[2] These amounts relate to derivatives which represent currency forward contracts valued primarily based on observable inputs, including forward and spot prices for currencies, netted against contracted rates and then multiplied against notional amounts, and are included within "prepaid expenses and other" and "accounts payable and accrued expenses" on December 31, 2016 and December 31, 2015, in the consolidated balance sheet with the corresponding gain or loss being recognized within "Derivatives and foreign currency transaction gains (losses)" in the consolidated statement of operations and comprehensive income.

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Note 8 - Fair Value of Financial Instruments - Amounts of Gain (Loss) Recognized in Condensed Consolidated Statements on Derivative Instruments Not Designated as Hedges (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Call options on natural gas price	$ (3,942)	$ (48)	$ 775
Foreign Currency Gain (Loss) [Member] | Call Option on Natural Gas Price [Member]
Call options on natural gas price	(1,340)
Foreign Currency Gain (Loss) [Member] | Call and Put Options on Oil Price [Member]
Call options on natural gas price	(1,313)
Foreign Currency Gain (Loss) [Member] | Contingent Considerations [Member]
Call options on natural gas price	(1,527)
Foreign Currency Gain (Loss) [Member] | Currency Forward Contracts [Member]
Call options on natural gas price	238	(1,206)	(4,949)
Electricity Revenues [Member] | Crude Oil Price Swap [Member]
Call options on natural gas price			2,728
Electricity Revenues [Member] | Natural Gas Price Swap [Member]
Call options on natural gas price		$ 1,158	$ 2,996

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Note 8 - Fair Value of Financial Instruments - Fair Value of Long-term Debt Approximates Its Carrying Amount, Exceptions (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Estimate of Fair Value Measurement [Member]
Fair value levels-secured, unsecured and long term debt	$ 10.4	$ 6.7
Reported Value Measurement [Member]
Fair value levels-secured, unsecured and long term debt	11.2	6.7
Olkaria III DEG [Member]
Fair value levels-secured, unsecured and long term debt	16.3	24.2
Olkaria III DEG [Member] | Estimate of Fair Value Measurement [Member]
Loans	16.3	24.2
Olkaria III DEG [Member] | Reported Value Measurement [Member]
Loans	15.8	23.7
Olkaria III OPIC [Member]
Fair value levels-secured, unsecured and long term debt	253.4	262.6
Olkaria III OPIC [Member] | Estimate of Fair Value Measurement [Member]
Loans	253.4	262.6
Olkaria III OPIC [Member] | Reported Value Measurement [Member]
Loans	246.6	264.6
Olkaria IV Loan - DEG 2 [Member]
Fair value levels-secured, unsecured and long term debt	50.9
Olkaria IV Loan - DEG 2 [Member] | Estimate of Fair Value Measurement [Member]
Loans	50.9
Olkaria IV Loan - DEG 2 [Member] | Reported Value Measurement [Member]
Loans	50.0
Amatitlan Loan [Member]
Fair value levels-secured, unsecured and long term debt	37.3	41.7
Amatitlan Loan [Member] | Estimate of Fair Value Measurement [Member]
Loans	37.3	41.7
Amatitlan Loan [Member] | Reported Value Measurement [Member]
Loans	36.8	40.3
Ormat Funding Corp [Member]
Fair value levels-secured, unsecured and long term debt	17.0	30.0
Ormat Funding Corp [Member] | Estimate of Fair Value Measurement [Member]
Notes	17.0	30.0
Ormat Funding Corp [Member] | Reported Value Measurement [Member]
Notes	17.0	30.0
Orcal Geothermal Inc [Member]
Fair value levels-secured, unsecured and long term debt	37.4	43.8
Orcal Geothermal Inc [Member] | Estimate of Fair Value Measurement [Member]
Notes	37.4	43.8
Orcal Geothermal Inc [Member] | Reported Value Measurement [Member]
Notes	35.2	43.3
OFC Two Senior Secured Notes [Member]
Fair value levels-secured, unsecured and long term debt	249.0	231.1
OFC Two Senior Secured Notes [Member] | Estimate of Fair Value Measurement [Member]
Notes	249.0	231.1
OFC Two Senior Secured Notes [Member] | Reported Value Measurement [Member]
Notes	247.2	262.0
Don A. Campbell 1 ("DAC1") [Member]
Fair value levels-secured, unsecured and long term debt	88.9
Don A. Campbell 1 ("DAC1") [Member] | Estimate of Fair Value Measurement [Member]
Notes	88.9
Don A. Campbell 1 ("DAC1") [Member] | Reported Value Measurement [Member]
Notes	92.4
Senior Unsecured Bonds [Member]
Fair value levels-secured, unsecured and long term debt	200.1	264.5
Senior Unsecured Bonds [Member] | Estimate of Fair Value Measurement [Member]
Senior Unsecured Bonds	200.1	264.5
Senior Unsecured Bonds [Member] | Reported Value Measurement [Member]
Senior Unsecured Bonds	$ 204.3	$ 250.0

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Note 8 - Fair Value of Financial Instruments - Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Deposits	$ 14.4	$ 15.9
Fair Value, Inputs, Level 1 [Member]
Deposits	14.4	15.9
Fair Value, Inputs, Level 2 [Member]
Deposits
Fair Value, Inputs, Level 3 [Member]
Deposits
Olkaria III DEG [Member]
Fair value levels-secured, unsecured and long term debt	16.3	24.2
Olkaria III DEG [Member] | Fair Value, Inputs, Level 1 [Member]
Fair value levels-secured, unsecured and long term debt
Olkaria III DEG [Member] | Fair Value, Inputs, Level 2 [Member]
Fair value levels-secured, unsecured and long term debt
Olkaria III DEG [Member] | Fair Value, Inputs, Level 3 [Member]
Fair value levels-secured, unsecured and long term debt	16.3	24.2
Olkaria III OPIC [Member]
Fair value levels-secured, unsecured and long term debt	253.4	262.6
Olkaria III OPIC [Member] | Fair Value, Inputs, Level 1 [Member]
Fair value levels-secured, unsecured and long term debt
Olkaria III OPIC [Member] | Fair Value, Inputs, Level 2 [Member]
Fair value levels-secured, unsecured and long term debt
Olkaria III OPIC [Member] | Fair Value, Inputs, Level 3 [Member]
Fair value levels-secured, unsecured and long term debt	253.4	262.6
Olkaria IV Loan - DEG 2 [Member]
Fair value levels-secured, unsecured and long term debt	50.9
Olkaria IV Loan - DEG 2 [Member] | Fair Value, Inputs, Level 1 [Member]
Fair value levels-secured, unsecured and long term debt
Olkaria IV Loan - DEG 2 [Member] | Fair Value, Inputs, Level 2 [Member]
Fair value levels-secured, unsecured and long term debt
Olkaria IV Loan - DEG 2 [Member] | Fair Value, Inputs, Level 3 [Member]
Fair value levels-secured, unsecured and long term debt	50.9
Amatitlan Loan [Member]
Fair value levels-secured, unsecured and long term debt	37.3	41.7
Amatitlan Loan [Member] | Fair Value, Inputs, Level 1 [Member]
Fair value levels-secured, unsecured and long term debt
Amatitlan Loan [Member] | Fair Value, Inputs, Level 2 [Member]
Fair value levels-secured, unsecured and long term debt	37.3	41.7
Amatitlan Loan [Member] | Fair Value, Inputs, Level 3 [Member]
Fair value levels-secured, unsecured and long term debt
Ormat Funding Corp [Member]
Fair value levels-secured, unsecured and long term debt	17.0	30.0
Ormat Funding Corp [Member] | Fair Value, Inputs, Level 1 [Member]
Fair value levels-secured, unsecured and long term debt
Ormat Funding Corp [Member] | Fair Value, Inputs, Level 2 [Member]
Fair value levels-secured, unsecured and long term debt	17.0	30.0
Ormat Funding Corp [Member] | Fair Value, Inputs, Level 3 [Member]
Fair value levels-secured, unsecured and long term debt
Orcal Geothermal Inc [Member]
Fair value levels-secured, unsecured and long term debt	37.4	43.8
Orcal Geothermal Inc [Member] | Fair Value, Inputs, Level 1 [Member]
Fair value levels-secured, unsecured and long term debt
Orcal Geothermal Inc [Member] | Fair Value, Inputs, Level 2 [Member]
Fair value levels-secured, unsecured and long term debt
Orcal Geothermal Inc [Member] | Fair Value, Inputs, Level 3 [Member]
Fair value levels-secured, unsecured and long term debt	37.4	43.8
OFC Two Senior Secured Notes [Member]
Fair value levels-secured, unsecured and long term debt	249.0	231.1
OFC Two Senior Secured Notes [Member] | Fair Value, Inputs, Level 1 [Member]
Fair value levels-secured, unsecured and long term debt
OFC Two Senior Secured Notes [Member] | Fair Value, Inputs, Level 2 [Member]
Fair value levels-secured, unsecured and long term debt
OFC Two Senior Secured Notes [Member] | Fair Value, Inputs, Level 3 [Member]
Fair value levels-secured, unsecured and long term debt	249.0	231.1
Senior Unsecured Bonds [Member]
Fair value levels-secured, unsecured and long term debt	200.1	264.5
Senior Unsecured Bonds [Member] | Fair Value, Inputs, Level 1 [Member]
Fair value levels-secured, unsecured and long term debt
Senior Unsecured Bonds [Member] | Fair Value, Inputs, Level 2 [Member]
Fair value levels-secured, unsecured and long term debt
Senior Unsecured Bonds [Member] | Fair Value, Inputs, Level 3 [Member]
Fair value levels-secured, unsecured and long term debt	200.1	264.5
Don A. Campbell 1 ("DAC1") [Member]
Fair value levels-secured, unsecured and long term debt	88.9
Don A. Campbell 1 ("DAC1") [Member] | Fair Value, Inputs, Level 1 [Member]
Fair value levels-secured, unsecured and long term debt
Don A. Campbell 1 ("DAC1") [Member] | Fair Value, Inputs, Level 2 [Member]
Fair value levels-secured, unsecured and long term debt
Don A. Campbell 1 ("DAC1") [Member] | Fair Value, Inputs, Level 3 [Member]
Fair value levels-secured, unsecured and long term debt	88.9
Other Long-term Debt [Member]
Fair value levels-secured, unsecured and long term debt	10.4	6.7
Other Long-term Debt [Member] | Fair Value, Inputs, Level 1 [Member]
Fair value levels-secured, unsecured and long term debt
Other Long-term Debt [Member] | Fair Value, Inputs, Level 2 [Member]
Fair value levels-secured, unsecured and long term debt	3.3	6.7
Other Long-term Debt [Member] | Fair Value, Inputs, Level 3 [Member]
Fair value levels-secured, unsecured and long term debt	$ 7.1

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Note 9 - Property, Plant and Equipment and Construction-in-process (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Depreciation	$ 94.8	$ 95.2	$ 87.9
Depreciation Net Of Amortization Of Cash Grant	5.5	5.5	$ 5.3
Property, Plant and Equipment Including Construction In Progress, Net	1,376.1	1,335.0
Property, Plant and Equipment, Cash Grant, Net	138.7	144.2
Orzunil I de Electricidad, Limitada [Member]
Property, Plant and Equipment Including Construction In Progress, Net	12.2	19.2
Ortitlan Limitada [Member]
Property, Plant and Equipment Including Construction In Progress, Net	$ 40.3	46.0
Kenya Power and Lighting Co Limited [Member]
Power Purchase Agreements Term	20 years
Zunil Power Plant In Guatemala [Member] | Instituto Nacional de Electrificacion (INDE) [Member]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	3.00%
Foreign Countries [Member]
Property, Plant and Equipment Including Construction In Progress, Net	$ 487.0	473.1
KENYA | Power Plants [Member]
Property, Plant and Equipment Including Construction In Progress, Net	$ 315.0	$ 355.8

XML

Note 9 - Property, Plant and Equipment and Construction-in-process - Property, Plant and Equipment, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Property, plant and equipment	$ 2,436,858	$ 2,344,789
Asset retirement cost	8,669	7,961
Less accumulated depreciation	(880,480)	(785,454)
Property, plant and equipment, net	1,556,378	1,559,335
Land [Member]
Property, plant and equipment	31,904	31,465
Leasehold Improvements [Member]
Property, plant and equipment	3,848	3,691
Machinery and Equipment [Member]
Property, plant and equipment	152,821	133,457
Office Equipment [Member]
Property, plant and equipment	28,634	29,247
Automobiles [Member]
Property, plant and equipment	11,161	7,782
Geothermal And Recovered Energy Generation Power Plants [Member] | UNITED STATES
Property, plant and equipment	1,658,195	1,637,081
Geothermal And Recovered Energy Generation Power Plants [Member] | Foreign Countries [Member]
Property, plant and equipment	$ 541,626	$ 494,105

XML

Note 9 - Property, Plant and Equipment and Construction-in-process - Construction-in-process (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Construction-in-process	$ 306,709	$ 248,835
Projects Under Exploration And Development [Member]
Construction-in-process	54,447	62,920	$ 73,431	$ 69,639
Projects Under Exploration And Development [Member] | Up-front Bonus Lease Costs [Member]
Construction-in-process	17,385	26,491	26,618	30,141
Projects Under Exploration And Development [Member] | Exploration And Development Costs [Member]
Construction-in-process	36,359	35,726	45,977	38,220
Projects Under Exploration And Development [Member] | Interest Capitalized [Member]
Construction-in-process	703	703	$ 836	$ 1,278
Projects Under Construction [Member]
Construction-in-process	252,262	185,915
Projects Under Construction [Member] | Up-front Bonus Lease Costs [Member]
Construction-in-process	37,713	27,473
Projects Under Construction [Member] | Interest Capitalized [Member]
Construction-in-process	12,338	7,975
Projects Under Construction [Member] | Drilling And Construction Costs [Member]
Construction-in-process	$ 202,211	$ 150,467

XML

Note 9 - Property, Plant and Equipment and Construction-in-process - Activity in Construction and Development (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Balance				$ 248,835					$ 248,835
Write off of unsuccessful exploration costs	$ (303)	$ (1,294)	$ (863)	(557)	$ (1,220)	$ (185)		$ (174)	(3,017)	$ (1,579)	$ (15,439)
Balance	306,709				248,835				306,709	248,835
Projects Under Exploration And Development [Member]
Balance				62,920				73,431	62,920	73,431	69,639
Cost incurred during the year									26,679	11,010	19,231
Write off of unsuccessful exploration costs									(3,017)	(1,579)	(15,439)
Balance	54,447				62,920				54,447	62,920	73,431
Transfer of projects under exploration and development to projects under construction									(32,135)	(19,942)
Projects Under Exploration And Development [Member] | Up-front Bonus Lease Costs [Member]
Balance				26,491				26,618	26,491	26,618	30,141
Cost incurred during the year									1,514	37
Write off of unsuccessful exploration costs									(380)	(164)	(3,523)
Balance	17,385				26,491				17,385	26,491	26,618
Transfer of projects under exploration and development to projects under construction									(10,240)
Projects Under Exploration And Development [Member] | Exploration And Development Costs [Member]
Balance				35,726				45,977	35,726	45,977	38,220
Cost incurred during the year									25,165	10,104	19,231
Write off of unsuccessful exploration costs									(2,637)	(1,415)	(11,474)
Balance	36,359				35,726				36,359	35,726	45,977
Transfer of projects under exploration and development to projects under construction									(21,895)	(18,940)
Projects Under Exploration And Development [Member] | Interest Capitalized [Member]
Balance				703				836	703	836	1,278
Cost incurred during the year										869
Write off of unsuccessful exploration costs											(442)
Balance	703				703				703	703	836
Transfer of projects under exploration and development to projects under construction										(1,002)
Construction in Progress [Member]
Balance				185,915				223,291	185,915	223,291	219,187
Cost incurred during the year									122,757	144,533	135,803
Balance	252,262				185,915				252,262	185,915	223,291
Transfer of projects under exploration and development to projects under construction									32,135	19,942
Transfer of completed projects to property, plant and equipment									(88,545)	(201,851)	(106,096)
Sale of property, plant and equipment											(25,603)
Construction in Progress [Member] | Up-front Bonus Lease Costs [Member]
Balance				27,473				27,473	27,473	27,473	27,473
Cost incurred during the year
Balance	37,713				27,473				37,713	27,473	27,473
Transfer of projects under exploration and development to projects under construction									10,240
Transfer of completed projects to property, plant and equipment
Sale of property, plant and equipment
Construction in Progress [Member] | Drilling And Construction Costs [Member]
Balance				150,467				187,545	150,467	187,545	184,766
Cost incurred during the year									116,247	140,977	132,597
Balance	202,211				150,467				202,211	150,467	187,545
Transfer of projects under exploration and development to projects under construction									21,895	18,940
Transfer of completed projects to property, plant and equipment									(86,398)	(196,995)	(105,126)
Sale of property, plant and equipment											(24,692)
Construction in Progress [Member] | Interest Capitalized [Member]
Balance				$ 7,975				$ 8,273	7,975	8,273	6,948
Cost incurred during the year									6,510	3,556	3,206
Balance	$ 12,338				$ 7,975				12,338	7,975	8,273
Transfer of projects under exploration and development to projects under construction										1,002
Transfer of completed projects to property, plant and equipment									$ (2,147)	(4,856)	(970)
Sale of property, plant and equipment											$ (911)

XML

Note 10 - Intangible Assets and Goodwill (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jul. 31, 2016
Finite-Lived Intangible Assets, Net	$ 52,753,000	$ 25,900,000
Finite-Lived Intangible Assets, Accumulated Amortization	42,800,000	38,400,000
Amortization of Intangible Assets	4,400,000	3,300,000	$ 3,300,000
Increase (Decrease) in Intangible Assets, Current	33,000,000	500,000	0
Finite Lived Intangible Assets, Disposals	0	0	$ 0
Goodwill	6,650,000
Goodwill, Period Increase (Decrease), Except for Currency Translation Adjustment	$ 0
Geothermie Bouillante SA (“GB”) [Member]
Goodwill				$ 7,100,000

XML

Note 10 - Intangible Assets - Estimated Future Amortization Expense (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
2017	$ 5,042,000
2018	4,912,000
2019	4,839,000
2020	4,522,000
2021	4,522,000
Thereafter	28,916,000
Total	$ 52,753,000	$ 25,900,000

XML

Note 11 - Accounts Payable and Accrued Expenses - Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Trade payables	$ 48,309	$ 41,364
Salaries and other payroll costs	17,977	14,671
Customer advances	576	2,533
Accrued interest	3,524	8,252
Income tax payable	8,824	11,353
Property tax payable	1,884	3,609
Scheduling and transmission	964	1,547
Royalty accrual	1,639	1,818
Other	7,953	6,808
Total	$ 91,650	$ 91,955

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Note 12 - Long-term Debt and Credit Agreements (Details Textual)								1 Months Ended													3 Months Ended				12 Months Ended
	Dec. 21, 2016 USD ($)	Nov. 29, 2016 USD ($)	Sep. 14, 2016 USD ($)	Jul. 31, 2015 USD ($) MWh	Feb. 28, 2013 USD ($)	Nov. 30, 2012 USD ($)	Jul. 01, 2009 USD ($)	Aug. 18, 2014 USD ($)	Jun. 20, 2014 USD ($)	Nov. 30, 2013 USD ($)	May 31, 2013 USD ($)	Oct. 31, 2012 USD ($)	Feb. 29, 2012 USD ($)	Oct. 31, 2011 USD ($)	Nov. 30, 2010 USD ($)	Jul. 31, 2009 USD ($)	Mar. 31, 2009 USD ($)	Mar. 30, 2009 USD ($)	Dec. 31, 2005 USD ($)	Feb. 29, 2004 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2014 USD ($)	Mar. 31, 2013 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Oct. 20, 2016 USD ($)	Jun. 30, 2016	Oct. 31, 2015 USD ($)	Aug. 29, 2014 USD ($)	Jan. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Aug. 23, 2012 USD ($)	Feb. 28, 2012 USD ($)	Sep. 30, 2011 USD ($)	Feb. 28, 2011 USD ($)	Aug. 31, 2010 USD ($)
Letters of Credit Outstanding, Amount																									$ 341,600,000
Repayments of Long-term Debt																									62,052,000	$ 71,701,000	$ 111,180,000
Payments for Derivative Instrument, Financing Activities																											1,505,000
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax																									87,000	91,000	(902,000)
Proceeds from Issuance of Unsecured Debt																									$ 203,483,000
Debt To Earnings Before Interest Tax Depreciation And Amortization Ratio																									2.32
Stockholders' Equity Attributable to Parent																									$ 1,078,425,000	990,001,000
Percentage Of Company Assets																									47.53%
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest																									$ 1,170,007,000	1,083,874,000	786,746,000						$ 745,111,000
Payments of Dividends																									25,700,000
Interest Rate Cap [Member]
Payments for Derivative Instrument, Financing Activities								$ 1,500,000
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax																											900,000
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax																											$ 600,000
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net																									$ 100,000	$ 100,000
Covenant Requirement Minimum [Member]
Amount Available For Dividend Distribution Percent Of Cumulative Net Income																									0.35
Stockholders' Equity Attributable to Parent																									$ 600,000,000
Percentage Of Company Assets																									25.00%
London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument, Basis Spread on Variable Rate																										1.00%
Maximum [Member] | Covenant Requirement Minimum [Member]
Debt To Earnings Before Interest Tax Depreciation And Amortization Ratio																									6
Loan Agreement with Banco Industrial S.A. and Westrust Bank (International) Limited [Member]
Debt Instrument, Term				12 years
Debt Instrument, Face Amount				$ 42,000,000
Power Utilization | MWh				20
Debt Instrument, Payment Frequency				12 years
Long-term Debt, Gross																									$ 36,800,000
Loan Agreement with Banco Industrial S.A. and Westrust Bank (International) Limited [Member] | Historical [Member]
Debt Services, Coverage Ratio																									1.87
Loan Agreement with Banco Industrial S.A. and Westrust Bank (International) Limited [Member] | Projected [Member]
Debt Services, Coverage Ratio																									1.92
Loan Agreement with Banco Industrial S.A. and Westrust Bank (International) Limited [Member] | Covenant Requirement Minimum [Member]
Debt Services, Coverage Ratio				1.15
Loan Agreement with Banco Industrial S.A. and Westrust Bank (International) Limited [Member] | Covenant Required to not Limit Dividends [Member]
Debt Services, Coverage Ratio				1.25
Loan Agreement with Banco Industrial S.A. and Westrust Bank (International) Limited [Member] | London Interbank Offered Rate (LIBOR) [Member] | Guaranteed [Member]
Debt Instrument, Basis Spread on Variable Rate				4.35%
Loan Agreement with Banco Industrial S.A. and Westrust Bank (International) Limited [Member] | London Interbank Offered Rate (LIBOR) [Member] | Not Guaranteed [Member]
Debt Instrument, Basis Spread on Variable Rate				4.75%
Loan Agreement with Banco Industrial S.A. and Westrust Bank (International) Limited [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument, Basis Spread on Variable Rate				1.25%
Loan Agreement with OPIC [Member]
Debt Instrument, Face Amount																																		$ 310,000,000
Debt Services, Coverage Ratio																									1.7
Long-term Debt, Gross																									$ 246,600,000
Restricted Cash and Cash Equivalents, Current																									4,300,000	$ 7,200,000
Letters of Credit Outstanding, Amount																									$ 17,300,000
Loan Agreement with OPIC [Member] | In The First Two Years After The Plant2 Commercial Operation Date [Member]
Debt Instrument, Prepayment Premium Percentage																									2.00%
Loan Agreement with OPIC [Member] | Third Year After the Plant 2 Commercial Operation Date [Member]
Debt Instrument, Prepayment Premium Percentage																									1.00%
Loan Agreement with OPIC [Member] | Historical [Member]
Debt Services, Coverage Ratio																									2.69
Loan Agreement with OPIC [Member] | Projected [Member]
Debt Services, Coverage Ratio																									2.96
Loan Agreement with OPIC [Member] | Tranche One [Member]
Debt Instrument, Face Amount						$ 85,000,000
Long-term Debt, Gross																									$ 66,000,000
Debt Instrument, Interest Rate, Stated Percentage																									6.31%
Loan Agreement with OPIC [Member] | Tranche Two [Member]
Debt Instrument, Face Amount						180,000,000
Long-term Debt, Gross						135,000,000																			$ 142,900,000
Proceeds from Issuance of Debt					$ 45,000,000
Debt Instrument, Interest Rate, Stated Percentage																									2.00%
Loan Agreement with OPIC [Member] | Tranche Three [Member]
Debt Instrument, Face Amount						45,000,000
Long-term Debt, Gross																									$ 37,600,000
Proceeds from Issuance of Debt										$ 45,000,000
Debt Instrument, Interest Rate, Stated Percentage																									6.12%
Loan Agreement with OPIC [Member] | Threshold For Loan Default [Member]
Debt Services, Coverage Ratio																											1.1
Loan Agreement with OPIC [Member] | Minimum [Member] | Historical [Member]
Debt Services, Coverage Ratio																											1.4
Olkaria III DEG [Member]
Debt Instrument, Face Amount												$ 20,500,000					$ 77,000,000	$ 105,000,000
Debt Instrument, Basis Spread on Variable Rate																	4.00%
Long-term Debt, Gross																									$ 15,800,000
Proceeds from Issuance of Debt							$ 15,000,000											$ 90,000,000
Debt Instrument, Interest Rate, Stated Percentage																	6.90%
Olkaria III DEG [Member] | Tranche One [Member]
Prepayment Deposit On Debt						20,500,000
Prepayment Penalty Charges						$ 1,500,000
Olkaria III DEG [Member] | Subject to Fixed Interest Rate [Member] | Loans Payable [Member]
Secured Debt																									10,800,000
Olkaria III DEG [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument, Basis Spread on Variable Rate												1.25%
Ormat Funding Corp [Member]
Debt Instrument, Face Amount																				$ 190,000,000
Proceeds from Issuance of Debt																				$ 179,700,000
Debt Instrument, Interest Rate, Stated Percentage																				8.25%
Restricted Cash and Cash Equivalents, Current																									2,100,000	1,400,000
Letters of Credit Outstanding, Amount																									$ 11,500,000	11,600,000
Debt Instrument, Issuance Costs																				$ 10,300,000
Ormat Funding Corp [Member] | Senior Notes [Member]
Debt Instrument, Repurchase Amount					$ 12,800,000																$ 6,800,000	$ 30,600,000										$ 13,200,000
Gain (Loss) on Extinguishment of Debt																					$ (600,000)	$ (1,700,000)	$ 300,000	$ 800,000
Ormat Funding Corp [Member] | Historical [Member]
Debt Services, Coverage Ratio																									1.25
Ormat Funding Corp [Member] | Projected [Member]
Debt Services, Coverage Ratio																									1.38
Ormat Funding Corp [Member] | Minimum [Member]
Debt Services, Coverage Ratio																				1.25
Ormat Funding Corp [Member] | Minimum [Member] | Senior Notes [Member]
Debt Instrument, Redemption Price, Percentage																									100.00%
Ormat Funding Corp [Member] | Maximum [Member] | Senior Notes [Member]
Debt Instrument, Redemption Price, Percentage																									101.00%
Ormat Funding Corp Senior Secured Notes [Member] | Senior Notes [Member]
Secured Debt																									$ 17,000,000	30,000,000
OrCal Senior Secured Notes [Member]
Debt Instrument, Face Amount																			$ 165,000,000
Proceeds from Issuance of Debt																			$ 161,100,000
Debt Instrument, Interest Rate, Stated Percentage																			6.21%
Restricted Cash and Cash Equivalents, Current																									1,900,000	1,600,000
Letters of Credit Outstanding, Amount																									$ 35,200,000	43,300,000
Debt Instrument, Issuance Costs																			$ 3,900,000
Debt Instrument, Redemption Price, Percentage																									100.00%
OrCal Senior Secured Notes [Member] | Historical [Member]
Debt Services, Coverage Ratio																									1.77
OrCal Senior Secured Notes [Member] | Projected [Member]
Debt Services, Coverage Ratio																									2.57
OrCal Senior Secured Notes [Member] | Debt Service Reserve Backing [Member]
Letters of Credit Outstanding, Amount																									$ 4,600,000	5,500,000
OrCal Senior Secured Notes [Member] | Minimum [Member]
Debt Services, Coverage Ratio																			1.25
OFC Two Senior Secured Notes [Member]
Debt Instrument, Face Amount																																				$ 350,000,000
Government Guarantee Percent																									80.00%
Debtor-in-Possession Financing, Letters of Credit Outstanding																									$ 21,000,000
OFC Two Senior Secured Notes [Member] | Wholly Owned Subsidiaries With Project Debt [Member]
Debt Instrument, Face Amount																															$ 140,000,000
Debt Instrument, Interest Rate, Stated Percentage																															4.61%
OFC Two Senior Secured Notes [Member] | Senior Notes [Member]
Secured Debt																									$ 247,200,000	$ 262,000,000
OFC Two Senior Secured Notes [Member] | Historical [Member]
Debt Services, Coverage Ratio																									2.09				2.49
OFC Two Senior Secured Notes [Member] | Projected [Member]
Debt Services, Coverage Ratio																									2.05				1.98
OFC Two Senior Secured Notes [Member] | Phase One Series A Senior Notes [Member]
Debt Instrument, Face Amount														$ 151,700,000
Proceeds from Issuance of Debt														$ 141,100,000
Debt Instrument, Interest Rate, Stated Percentage														4.687%
Repayments of Long-term Debt									$ 4,300,000
Other Reserves																									$ 9,700,000						$ 28,000,000
OFC Two Senior Secured Notes [Member] | McGinness Hills Phase II [Member]
Letters of Credit Outstanding, Amount																									$ 53,400,000
OFC Two Senior Secured Notes [Member] | Minimum [Member] | Historical [Member]
Debt Services, Coverage Ratio																									1.2
OFC Two Senior Secured Notes [Member] | Minimum [Member] | Projected [Member]
Debt Services, Coverage Ratio																									1.5
Don A. Cambell Senior Secured Notes [Member]
Debt Instrument, Face Amount		$ 92,500,000
Debt Services, Coverage Ratio																									1.85
Proceeds from Issuance of Debt		$ 87,100,000
Debt Instrument, Interest Rate, Stated Percentage		4.03%
Secured Debt																									$ 92,400,000
Debt Instrument, Minimum Prepay Amount		$ 2,000,000
Don A. Cambell Senior Secured Notes [Member] | Minimum [Member]
Debt Services, Coverage Ratio		1.2
Senior Unsecured Bonds [Member]
Debt Instrument, Face Amount			$ 204,000,000																																		$ 107,500,000	$ 142,000,000
Debt Instrument, Interest Rate, Stated Percentage																																					6.75%	7.00%
Proceeds from Issuance of Unsecured Debt			250,000,000
Senior Unsecured Bonds [Member] | Series 2 Bonds [Member]
Debt Instrument, Face Amount			67,000,000
Senior Unsecured Bonds [Member] | Series 3 Bonds [Member]
Debt Instrument, Face Amount			137,000,000
Senior Unsecured Bonds, Series 2 [Member]
Debt Instrument, Face Amount			$ 67,000,000
Debt Instrument, Interest Rate, Stated Percentage			3.70%
Senior Unsecured Bonds, Series 3 [Member]
Debt Instrument, Face Amount			$ 137,000,000
Debt Instrument, Interest Rate, Stated Percentage			4.45%
Institutional Investors [Member] | First Loan [Member]
Debt Instrument, Term																6 years
Debt Instrument, Face Amount																$ 20,000,000
Debt Instrument, Interest Rate, Stated Percentage																6.50%
Institutional Investors [Member] | Second Loan [Member]
Debt Instrument, Term																8 years
Debt Instrument, Face Amount																$ 20,000,000
Debt Instrument, Basis Spread on Variable Rate																5.00%
Long-term Line of Credit																									3,300,000
Institutional Investors [Member] | Third Loans [Member]
Debt Instrument, Term															6 years
Debt Instrument, Face Amount															$ 20,000,000
Debt Instrument, Interest Rate, Stated Percentage															5.75%
Debt Instrument, Repurchase Amount																														$ 6,200,000
DEG 2 Facility Agreement [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.28%
Debt Instrument, Minimum Prepay Amount	$ 5,000,000
Long-term Line of Credit																									50,000,000
Line of Credit Facility, Maximum Borrowing Capacity																												$ 50,000,000
Proceeds from Lines of Credit	$ 50,000,000
Revolving Credit Lines with Commercial Banks [Member]
Long-term Line of Credit																									0
Line of Credit Facility, Maximum Borrowing Capacity																									524,800,000
Revolving Credit Lines with Commercial Banks [Member] | Extensions Of Credit In The Form Of Loans And/Or Letters of Credit [Member]
Line of Credit Facility, Maximum Borrowing Capacity																									215,000,000
Revolving Credit Lines with Commercial Banks [Member] | Issuance Of Letters Of Credit [Member]
Letters of Credit Outstanding, Amount																									$ 309,800,000
Union Bank, N.A. [Member]
Debt Services, Coverage Ratio																									2.54
Letters of Credit Outstanding, Amount																									$ 32,600,000
Line of Credit Facility, Maximum Borrowing Capacity																									$ 60,000,000
Debt To Earnings Before Interest Tax Depreciation And Amortization Ratio																									2.95
Amount Available For Dividend Distribution Percent Of Cumulative Net Income																									0.81
Union Bank, N.A. [Member] | Minimum [Member]
Debt Services, Coverage Ratio													1.35
Line of Credit Facility, Maximum Borrowing Capacity																																			$ 39,000,000
Union Bank, N.A. [Member] | Maximum [Member]
Line of Credit Facility, Maximum Borrowing Capacity													$ 60
Debt To Earnings Before Interest Tax Depreciation And Amortization Ratio													4.5
Amount Available For Dividend Distribution Percent Of Cumulative Net Income													2
HSBC Bank USA, N.A. [Member]
Debt Services, Coverage Ratio																									2.54
Letters of Credit Outstanding, Amount																									$ 23,200,000
Line of Credit Facility, Maximum Borrowing Capacity											$ 35,000,000														$ 35,000,000
Debt To Earnings Before Interest Tax Depreciation And Amortization Ratio																									2.95
Amount Available For Dividend Distribution Percent Of Cumulative Net Income																									0.81
Line of Credit Facility, Borrowing Capacity Increase											10,000,000
Line of Credit Facility, Capacity Available for Specific Purpose Other than for Trade Purchases											$ 10,000,000
HSBC Bank USA, N.A. [Member] | Minimum [Member]
Debt Services, Coverage Ratio											1.35
HSBC Bank USA, N.A. [Member] | Maximum [Member]
Debt To Earnings Before Interest Tax Depreciation And Amortization Ratio											4.5
Amount Available For Dividend Distribution Percent Of Cumulative Net Income											2

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Note 12 - Long-term Debt and Credit Agreements - Long-term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
	$ 681,548	$ 640,133
Less current portion	(53,729)	(51,425)
Non current portion	627,819	588,708
Recourse Debt	274,983	280,332
Less current portion	(12,242)	(11,229)
Non current portion	262,741	269,103
Other Loans, Limited and Non-recourse [Member]
Non-Recourse Debt	6,368
Loan Agreement With OPIC The Olkaria III Power Plant [Member]
Non-Recourse Debt	246,630	264,624
Loan Agreement with Banco Industrial S.A. and Westrust Bank (International) Limited [Member]
Non-Recourse Debt	36,750	40,250
Ormat Funding Corp [Member]
Non-Recourse Debt	17,026	29,968
Orcal Geothermal Inc [Member]
Non-Recourse Debt	35,181	43,332
Don A. Campbell 1 ("DAC1") [Member]
Non-Recourse Debt	92,361
OFC Two Senior Secured Notes [Member]
Non-Recourse Debt	247,232	261,959
Senior Unsecured Bonds [Member]
Recourse Debt	204,332	249,981
Institutional Investors [Member]
Recourse Debt	3,333	6,667
Olkaria III DEG [Member]
Recourse Debt	65,789	23,684
Loan From Commercial Bank [Member]
Recourse Debt	1,529
Revolving Credit Lines With Banks [Member]
Recourse Debt

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Note 12 - Long-term Debt and Credit Agreements - Future Minimum Payments Under Long-term Obligations (Details) $ in Thousands	Dec. 31, 2016 USD ($)
2017	$ 65,971
2018	64,805
2019	59,146
2020	126,870
2021	46,579
Thereafter	593,161
Total	$ 956,532

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Note 13 - Puna Power Plant Lease Transactions (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2005	Dec. 31, 2015
Lease Term		31 years
Deferred Revenue, Leases, Gross		$ 83,000,000
Capital Leases, Balance Sheet, Assets by Major Class, Net	$ 28,000,000		$ 30,700,000
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation	$ 32,900,000		30,200,000
Lease Payment Term	23 years
Deferred Costs, Leasing, Gross	$ 4,200,000
Restricted Cash and Cash Equivalents	2,900,000		2,100,000
Cash	$ 0		$ 0

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Note 13 - Puna Power Plant Lease Transactions - Future Minimum Lease Payments Under the Project Lease (Details) $ in Thousands	Dec. 31, 2016 USD ($)
2017	$ 8,747
2018	8,944
2019	6,018
2020	2,450
2021	1,723
Thereafter	2,740
Total	$ 30,622

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Note 14 - Tax Monetization Transactions (Details Textual) $ in Thousands					1 Months Ended			3 Months Ended	12 Months Ended					72 Months Ended
	Dec. 31, 2022	Dec. 16, 2016 USD ($)	Feb. 03, 2011 USD ($)	Oct. 30, 2009 USD ($)	Jan. 31, 2014	Jan. 31, 2013 USD ($)	Jun. 30, 2007	Dec. 31, 2009 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2008 USD ($)	Dec. 31, 2007 USD ($)	Dec. 31, 2022 USD ($)	Mar. 31, 2017 USD ($)	Dec. 15, 2016	Mar. 31, 2016 USD ($)	Dec. 31, 2010	Oct. 03, 2009
Proceeds from Noncontrolling Interests									$ 1,972	$ 1,654	$ 2,234
Noncontrolling Interest, Increase from Subsidiary Equity Issuance									44,102	156,635
Proceeds from Sales of Business, Affiliate and Productive Assets											$ 35,250
Proceeds from Additional Payments																	$ 2,000
Subsequent Event [Member]
Proceeds from Additional Payments															$ 1,600
Opal Geo LLC [Member]
Percentage Of Distributable Cash to Controlling Interest		97.50%
Percentage of Income (Loss), Gain, Deduction and Credit Allocated to Controlling Interests		1.00%
Percentage of Income (Loss), Gain, Deduction and Credit Allocated to Controlling Interests, PTCs Not Available		95.00%
Opal Geo LLC [Member] | Scenario, Forecast [Member]
Percentage of Income (Loss), Gain, Deduction and Credit Allocated to Controlling Interests	95.00%
Opal Geo LLC [Member] | JPM Capital Corporation [Member]
Proceeds from Noncontrolling Interests		$ 62,100
Percentage Of Distributable Cash to Nontrolling Interests		2.50%
Percentage of Income (Loss), Gain, Deduction and Credit Allocated to Noncontrolling Interests		99.00%
Percentage of Income (Loss), Gain, Deduction and Credit Allocated to Noncontrolling Interests, PTCs Not Available		5.00%
Opal Geo LLC [Member] | JPM Capital Corporation [Member] | Noncontrolling Interest [Member]
Proceeds from Noncontrolling Interests		$ 3,700
Opal Geo LLC [Member] | JPM Capital Corporation [Member] | Liability for Sale of Tax Benefit [Member]
Proceeds from Noncontrolling Interests		$ 58,500
Opal Geo LLC [Member] | JPM Capital Corporation [Member] | Scenario, Forecast [Member]
Proceeds from Noncontrolling Interests														$ 21,000
Percentage Of Distributable Cash to Nontrolling Interests	100.00%
Percentage of Income (Loss), Gain, Deduction and Credit Allocated to Noncontrolling Interests	5.00%
Opal Geo LLC [Member] | JPM Capital Corporation [Member] | Capital Unit, Class B [Member]
Percentage of Equity Interest Sold		100.00%
Ormat Nevada ORTP LLC [Member]
Percentage Of Ownership Interests																		82.50%
Number Of Facilities							4
Proceeds From Sale Of Equity Units												$ 63,000	$ 71,800
Percentage Of Ownership Interests Flip Date																		95.00%
Percentage Of Ownership Interests By Noncontrolling Owners Flip Date			5.00%															5.00%	3.50%
Payments for Repurchase of Redeemable Noncontrolling Interest				$ 18,500
Gain From Repurchase Of Interests At Discount								$ 13,300
Adjustments To Additional Paid In Capital Purchase Of Noncontrolling Interest								$ 1,100
Percentage Of Ownership Interests Purchased From Noncontrolling Owners			1.50%					1.50%
Proceeds Sale Minority Interest			$ 24,900
Noncontrolling Interest, Increase from Subsidiary Equity Issuance			$ 2,300
Proceeds from Sales of Business, Affiliate and Productive Assets						$ 35,700
Additional Proceeds As Percentage Of Production Tax Credit						25.00%
Percentage Of Distributable Cash After Flip Date						97.50%
Percentage Of Taxable Income After Flip Date						95.00%
Percentage Allocation Of Income And Loss						5.00%
Percentage Allocation Of Cash						2.50%
Final Additional Payments Expected Date					Dec. 31, 2016
Ormat Nevada ORTP LLC [Member] | Maximum [Member]
Expected Future Payments									$ 11,000
Ormat Nevada ORTP LLC [Member] | Common Class A [Member]
Common Stock Voting Rights Percentage						75.00%
Ormat Nevada ORTP LLC [Member] | Common Class B [Member]
Common Stock Voting Rights Percentage						25.00%
Ormat Nevada ORTP LLC [Member] | Capital Unit, Class B [Member]
Percentage Of Ownership Interests			7.50%
Ownership Percentage Of Common Shares Outstanding			30.00%
Ownership Percentage Of Common Shares Outstanding By Non Controlling Interest																		70.00%
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners																		17.50%
Ormat Nevada ORTP LLC [Member] | Capital Unit, Class A [Member]
Percentage Of Ownership Interests			75.00%
DAC 2 [Member]
Percentage Of Ownership Interests																63.25%
Other Geothermal Power Plants [Member]
Percentage Of Ownership Interests																100.00%
Opal Geo LLC [Member] | Capital Unit, Class A [Member]
Percentage Of Ownership Interests		100.00%
OPC LLC [Member] | JPM Capital Corporation [Member] | Capital Unit, Class B [Member]
Fair Value of Equity Interest Sold		$ 3,000
Nevada [Member]
Number of Power Plants		5

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Note 15 - Asset Retirement Obligations - Reconciliation of the Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Balance at beginning of year	$ 20,856	$ 19,142
Revision in estimated cash flows	303	(681)
Liabilities incurred	540	859
Accretion expense	1,649	1,536
Balance at end of year	$ 23,348	$ 20,856

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Note 16 - Stock-based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Millions							1 Months Ended	3 Months Ended			12 Months Ended
	Nov. 08, 2016	Jun. 13, 2016	Nov. 03, 2015	Nov. 05, 2014	Apr. 02, 2014	Feb. 11, 2014	May 31, 2012	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2004	Mar. 31, 2021	May 31, 2014
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized								$ 11.3			$ 11.3
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition											1 year 146 days
Share Based Compensation Arrangement By Share Based Payment Award Fair Value Assumptions Annual Forfeiture Rate								10.30%	9.66%	8.02%
Increase (Decrease) In Stock Based Compensation Expense Due To Forfeitures, Percent								7.00%	20.00%	12.00%
Share Based Compensation Arrangement By Share Based Payment Award Fair Value Assumptions Dividends Growth Rate											20.00%
Sharebased Compensation Arrangement By Sharebased Payment Award Fair Value Assumptions Weighted Average Expected Dividend Rate											1.10%
Share Price								$ 53.62	$ 36.47		$ 53.62	$ 36.47
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Exercisable, Number								557,350	842,911		557,350	842,911
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value											$ 18.0	$ 14.1
Weighted Average [Member]
Share Price								$ 43.99	$ 35.64		$ 43.99	$ 35.64
2004 Stock Incentive Plan [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period													10 years
2004 Stock Incentive Plan [Member] | Stock Options And Stock Appreciation Rights [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized													3,750,000
2004 Stock Incentive Plan [Member] | Stock Options And Stock Appreciation Rights [Member] | Share-based Compensation Award, Tranche One [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage													25.00%
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period													2 years
2004 Stock Incentive Plan [Member] | Stock Options And Stock Appreciation Rights [Member] | Share-based Compensation Award, Tranche Two [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage													25.00%
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period													3 years
2004 Stock Incentive Plan [Member] | Stock Options And Stock Appreciation Rights [Member] | Share-based Compensation Award, Tranche Three [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage													50.00%
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period													4 years
2004 Stock Incentive Plan [Member] | Employee Stock Option [Member] | Non Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period													1 year
2012 Stock Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant								1,058,150			1,058,150
2012 Stock Incentive Plan [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period							10 years
2012 Stock Incentive Plan [Member] | Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized															400,000
2012 Stock Incentive Plan [Member] | Chief Financial Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross						32,500
Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price						$ 24.57
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value						$ 5.78
2012 Stock Incentive Plan [Member] | Chief Executive Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross					400,000
Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price					$ 29.52
2012 Stock Incentive Plan [Member] | Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			1 year	1 year
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period			7 years	7 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross			45,000	52,500
Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price			$ 38.24	$ 28.23
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value				$ 7.01
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value			$ 8.68
2012 Stock Incentive Plan [Member] | Share-based Compensation Award, Tranche One [Member] | Chief Executive Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period					4 years
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period					6 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross					300,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value					$ 12.88
2012 Stock Incentive Plan [Member] | Share-based Compensation Award, Tranche Two [Member] | Chief Executive Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period					7 years 182 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value					$ 8.33
2012 Stock Incentive Plan [Member] | Share-based Compensation Award, Tranche Two [Member] | Chief Executive Officer [Member] | Scenario, Forecast [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number														100,000
2012 Stock Incentive Plan [Member] | Stock Options And Stock Appreciation Rights [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized							4,000,000
2012 Stock Incentive Plan [Member] | Stock Options And Stock Appreciation Rights [Member] | Share-based Compensation Award, Tranche One [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage							25.00%
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period							2 years
2012 Stock Incentive Plan [Member] | Stock Options And Stock Appreciation Rights [Member] | Share-based Compensation Award, Tranche Two [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage							25.00%
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period							3 years
2012 Stock Incentive Plan [Member] | Stock Options And Stock Appreciation Rights [Member] | Share-based Compensation Award, Tranche Three [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage							50.00%
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period							4 years
2012 Stock Incentive Plan [Member] | Employee Stock Option [Member] | Non Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period							1 year
2012 Stock Incentive Plan [Member] | Employee Stock Option [Member] | Chief Financial Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period						3 years
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period						5 years
2012 Stock Incentive Plan [Member] | Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		4 years
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period		6 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		1,080,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Exercise Price		$ 42.87
2012 Stock Incentive Plan [Member] | Stock Appreciation Rights (SARs) [Member] | Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	1 year
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	7 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 14.51
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	60,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Exercise Price	$ 47.46
2012 Stock Incentive Plan [Member] | Stock Appreciation Rights (SARs) [Member] | Senior Management [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		11.98
2012 Stock Incentive Plan [Member] | Stock Appreciation Rights (SARs) [Member] | Other Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 11.42
2012 Stock Incentive Plan [Member] | Stock Appreciation Rights (SARs) [Member] | Share-based Compensation Award, Tranche One [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage		50.00%
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		2 years
2012 Stock Incentive Plan [Member] | Stock Appreciation Rights (SARs) [Member] | Share-based Compensation Award, Tranche Two [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage		25.00%
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		3 years
2012 Stock Incentive Plan [Member] | Stock Appreciation Rights (SARs) [Member] | Share-based Compensation Award, Tranche Three [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage		25.00%
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		4 years

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Note 16 - Stock-based Compensation - Compensation Related to Stock-based Awards (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cost of revenues	$ 5,157	$ 3,955	$ 5,571
Tax effect on stock-based compensation expense	617	440	836
Net effect of stock-based compensation expense	4,540	3,515	4,735
Cost of Sales [Member]
Cost of revenues	2,400	1,753	3,076
Selling and Marketing Expense [Member]
Cost of revenues	247	123	261
General and Administrative Expense [Member]
Cost of revenues	$ 2,510	$ 2,079	$ 2,234

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Note 16 - Stock-based Compensation - Fair Value of Stock-based Award on the Date of Grant (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Risk-free interest rate	1.30%	1.40%	1.70%
Expected life (in years) (Year)	4 years 182 days	4 years	5 years 36 days
Dividend yield	1.10%	0.70%	0.90%
Expected volatility	30.70%	29.20%	35.10%
Forfeiture rate (weighted average)	8.40%	0.00%	0.00%

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Note 16 - Stock-based Compensation - Fair Value of Each Option Using Black-scholes Valuation Model Assumptions (Details)				12 Months Ended
	Nov. 03, 2015	Nov. 05, 2014	Feb. 11, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Risk-free interest rates				1.30%	1.40%	1.70%
Expected life (in years) (Year)				4 years 182 days	4 years	5 years 36 days
Dividend yield				1.10%	0.70%	0.90%
Expected volatility				30.70%	29.20%	35.10%
Chief Executive Officer [Member] | Options to Purchase 300,000 Shares of Common Stock [Member]
Risk-free interest rates				2.36%
Expected life (in years) (Year)				7 years 91 days
Dividend yield				0.90%
Expected volatility				42.80%
Chief Executive Officer [Member] | Options to Purchase 100,000 Shares of Common Stock [Member]
Risk-free interest rates				1.64%
Expected life (in years) (Year)				4 years 273 days
Dividend yield				0.90%
Expected volatility				33.10%
2012 Incentive Plan [Member] | Chief Financial Officer [Member]
Risk-free interest rates	1.35%	1.30%	0.81%
Expected life (in years) (Year)	4 years	4 years	3 years 136 days
Dividend yield	0.70%	0.70%	0.80%
Expected volatility	29.20%	32.40%	33.50%
Forfeiture rate	0.00%	0.00%	0.00%

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Note 16 - Stock-based Compensation - Fair Value of Stock-based Award Using Exercise Multiple-based Lattice SAR Pricing Model Assumptions (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Risk-free interest rate	1.30%	1.40%	1.70%
Expected life (in years) (Year)	4 years 182 days	4 years	5 years 36 days
Dividend yield	1.10%	0.70%	0.90%
Expected volatility	30.70%	29.20%	35.10%
Forfeiture rate	8.40%	0.00%	0.00%
Stock Appreciation Rights (SARs) [Member] | Senior Management and Other Employees [Member]
Risk-free interest rate	1.29%
Expected life (in years) (Year)	6 years
Dividend yield	1.14%
Expected volatility	30.70%
Stock Appreciation Rights (SARs) [Member] | Directors [Member]
Risk-free interest rate	1.65%
Expected life (in years) (Year)	7 years
Dividend yield	1.10%
Expected volatility	30.60%
Forfeiture rate	0.00%
Sub-optimal Exercise Factor	2.5
Stock Appreciation Rights (SARs) [Member] | Senior Management [Member]
Forfeiture rate	0.00%
Sub-optimal Exercise Factor	2.5
Stock Appreciation Rights (SARs) [Member] | Other Employees [Member]
Forfeiture rate	10.50%
Sub-optimal Exercise Factor	2

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Note 16 - Stock-based Compensation - Summary of the Status of the 2012 Incentive Plan (Details) - $ / shares		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Outstanding at beginning of year (in shares)		3,300
Outstanding at beginning of year (in dollars per share)		$ 2,438
Outstanding at end of year (in shares)		4,100	3,300
Outstanding at end of year (in dollars per share)			$ 2,438
2012 Incentive Plan [Member]
Outstanding at beginning of year (in shares)		2,438	4,477	4,710
Outstanding at beginning of year (in dollars per share)		$ 25.38	$ 27.48	$ 28.23
Stock Options (in shares)		1,155	45	485
Stock Options (in dollars per share)		$ 43.01	$ 38.24	$ 29.05
SARs* (in shares)	[1]
SARs* (in dollars per share)	[1]
Exercised (in shares)		(967)	(1,589)	(243)
Exercised (in dollars per share)		$ 25.33	$ 26.77	$ 24.10
Forfeited (in shares)		(57)	(125)	(116)
Forfeited (in dollars per share)		$ 24.12	$ 27.33	$ 23.20
Expired (in shares)		(4)	(370)	(359)
Expired (in dollars per share)		$ 26.84	$ 45.78	$ 42.70
Outstanding at end of year (in shares)		2,565	2,438	4,477
Outstanding at end of year (in dollars per share)		$ 33.36	$ 25.38	$ 27.48
Options and SARs exercisable at end of year (in shares)		557	858	2,106
Options and SARs exercisable at end of year (in dollars per share)		$ 25.22	$ 26.75	$ 31.25
Weighted-average fair value of options and SARs granted during the year (in dollars per share)		$ 11.61	$ 8.68	$ 9

[1] Upon exercise, SARs entitle the recipient to receive shares of common stock equal to the increase in value of the award between the grant date and the exercise date.

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Note 16 - Stock-based Compensation - Summary of Information About Stock-based Awards Outstanding (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Exercise Price (in dollars per share)		$ 2,438
Number of Shares Outstanding (in shares)	4,100	3,300
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	51959 years	27148 years
Aggregate Intrinsic Value, Options Outstanding	$ 557	$ 857
Number of Shares Exercisable (in shares)	2,700	2,400
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)	15827 years	8526 years
Exercise Price 1 [Member]
Exercise Price (in dollars per share)	$ 15	$ 15
Number of Shares Outstanding (in shares)	2,800	3,800
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	526 years	269 years
Aggregate Intrinsic Value, Options Outstanding	$ 15	$ 15
Number of Shares Exercisable (in shares)	2,800	3,800
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)	526 years	269 years
Exercise Price 2 [Member]
Exercise Price (in dollars per share)	$ 15	$ 15
Number of Shares Outstanding (in shares)	2,600	3,600
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	509 years	252 years
Aggregate Intrinsic Value, Options Outstanding	$ 15	$ 15
Number of Shares Exercisable (in shares)	2,600	3,600
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)	509 years	252 years
Exercise Price 3 [Member]
Exercise Price (in dollars per share)	$ 108	$ 326
Number of Shares Outstanding (in shares)	2,300	3,300
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	3608 years	5327 years
Aggregate Intrinsic Value, Options Outstanding	$ 108	$ 69
Number of Shares Exercisable (in shares)	2,300	3,300
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)	3608 years	1135 years
Exercise Price 4 [Member]
Exercise Price (in dollars per share)	$ 53	$ 100
Number of Shares Outstanding (in shares)	2,300	3,300
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	1761 years	1593 years
Aggregate Intrinsic Value, Options Outstanding	$ 28	$ 50
Number of Shares Exercisable (in shares)	2,300	3,300
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)	934 years	797 years
Exercise Price 5 [Member]
Exercise Price (in dollars per share)	$ 635	$ 938
Number of Shares Outstanding (in shares)	2,400	3,400
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	19226 years	12315 years
Aggregate Intrinsic Value, Options Outstanding	$ 140	$ 126
Number of Shares Exercisable (in shares)	2,400	3,400
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)	4247 years	1655 years
Exercise Price 6 [Member]
Exercise Price (in dollars per share)	$ 9	$ 33
Number of Shares Outstanding (in shares)	2,100	3,100
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	269 years	387 years
Aggregate Intrinsic Value, Options Outstanding	$ 1	$ 16
Number of Shares Exercisable (in shares)	2,100	3,100
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)	33 years	193 years
Exercise Price 7 [Member]
Exercise Price (in dollars per share)	$ 68	$ 135
Number of Shares Outstanding (in shares)	1,300	2,300
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	1905 years	1462 years
Aggregate Intrinsic Value, Options Outstanding	$ 68	$ 135
Number of Shares Exercisable (in shares)	1,300	2,300
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)	1905 years	1462 years
Exercise Price 8 [Member]
Exercise Price (in dollars per share)	$ 15	$ 45
Number of Shares Outstanding (in shares)	3,800	4,800
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	404 years	440 years
Aggregate Intrinsic Value, Options Outstanding	$ 15	$ 45
Number of Shares Exercisable (in shares)	3,800	4,800
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)	404 years	440 years
Exercise Price 9 [Member]
Exercise Price (in dollars per share)	$ 30	$ 64
Number of Shares Outstanding (in shares)	4,800	200
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	762 years	618 years
Aggregate Intrinsic Value, Options Outstanding	$ 30	$ 64
Number of Shares Exercisable (in shares)	4,800	200
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)	762 years	618 years
Exercise Price 10 [Member]
Exercise Price (in dollars per share)	$ 400	$ 15
Number of Shares Outstanding (in shares)	3,600	1,800
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	9640 years	124 years
Aggregate Intrinsic Value, Options Outstanding	$ 75	$ 15
Number of Shares Exercisable (in shares)	3,600	1,800
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)	1807 years	124 years
Exercise Price 11 [Member]
Exercise Price (in dollars per share)	$ 17	$ 45
Number of Shares Outstanding (in shares)	300	5,800
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	400 years	371 years
Aggregate Intrinsic Value, Options Outstanding	$ 17	$ 45
Number of Shares Exercisable (in shares)	300	5,800
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)	400 years	371 years
Exercise Price 12 [Member]
Exercise Price (in dollars per share)	$ 15	$ 3
Number of Shares Outstanding (in shares)	6,100	1,300
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	277 years	22 years
Aggregate Intrinsic Value, Options Outstanding		$ 3
Number of Shares Exercisable (in shares)		1,300
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)		22 years
Exercise Price 13 [Member]
Exercise Price (in dollars per share)	$ 45	$ 400
Number of Shares Outstanding (in shares)	5,800	4,600
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	692 years	2780 years
Aggregate Intrinsic Value, Options Outstanding	$ 45
Number of Shares Exercisable (in shares)	5,800
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)	692 years
Exercise Price 14 [Member]
Exercise Price (in dollars per share)	$ 1,080	$ 148
Number of Shares Outstanding (in shares)	5,500	1,300
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	11610 years	963 years
Aggregate Intrinsic Value, Options Outstanding		$ 148
Number of Shares Exercisable (in shares)		1,300
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)		963 years
Exercise Price 15 [Member]
Exercise Price (in dollars per share)	$ 60	$ 96
Number of Shares Outstanding (in shares)	6,900	300
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)	370 years	225 years
Aggregate Intrinsic Value, Options Outstanding		$ 96
Number of Shares Exercisable (in shares)		300
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)		225 years
Exercise Price 16 [Member]
Exercise Price (in dollars per share)		$ 15
Number of Shares Outstanding (in shares)		6,800
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)
Aggregate Intrinsic Value, Options Outstanding
Number of Shares Exercisable (in shares)
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)
Exercise Price 17 [Member]
Exercise Price (in dollars per share)		$ 15
Number of Shares Outstanding (in shares)		800
Weighted Average Remaining Contractual Life in Years, Options Outstanding (Year)
Aggregate Intrinsic Value, Options Outstanding		$ 15
Number of Shares Exercisable (in shares)		800
Weighted Average Remaining Contractual Life in Years, Options Exercisable (Year)

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Note 18 - Interest Expense, Net - Components of Interest Expense (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Interest related to sale of tax benefits									$ 9,349	$ 9,620	$ 12,413
Interest expense									61,327	67,032	75,447
Less — amount capitalized									(3,287)	(4,075)	(3,206)
Interest Expense	$ 15,828	$ 17,137	$ 18,401	$ 16,023	$ 18,142	$ 17,748	$ 18,859	$ 17,828	$ 67,389	$ 72,577	$ 84,654

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Note 19 - Income Taxes (Details Textual) $ in Thousands			3 Months Ended	12 Months Ended
	Dec. 16, 2016 USD ($)	Sep. 11, 2015 USD ($)	Dec. 31, 2016 USD ($) $ / kWh	Dec. 31, 2016 USD ($) $ / kWh shares	Dec. 31, 2015 USD ($) shares	Dec. 31, 2014 USD ($) shares	Dec. 31, 2013 USD ($)	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2004	Nov. 23, 2016
Deferred Tax Assets, Investments			$ 1,341	$ 1,341	$ 1,341
Deferred Tax Assets, Tax Credit Carryforwards, General Business			82,451	82,451	70,792
Deferred Tax Assets, Valuation Allowance			109,611	109,611	70,536	$ 111,280	$ 114,806
Undistributed Earnings of Foreign Subsidiaries			367,000	367,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate			$ 5,700	5,700	10,400
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations				$ 6,400	$ 1,300	600
Investment Tax Credit Per Unit | $ / kWh			2.3	2.3
Production Tax Credit Claim Period				10 years
Depreciation Bonus Period to Write Off The Reminder of Equipment Cost				60 days
Placed into Service after December 31, 2011 and Before January 1, 2017 [Member]
Depreciation Bonus Permitted Write Off Equipment Cost Percentage				50.00%
OrLeaf LLC [Member]
Distributions Received From Subsidiary	$ 43,100
Taxable Gain (Loss) on Distribution from Subsidiary	4,800
OrLeaf LLC [Member] | ORPD LLC [Member]
Distributions Received From Subsidiary	$ 19,000
Northleaf Geothermal Holdings, Northleaf [Member]
Equity Method Investment, Ownership Percentage											36.75%
Taxable Income Recognized				$ 21,400
Investment Tax Credit Carryforward [Member]
Deferred Tax Assets, Investments			$ 1,300	$ 1,300
Tax Credit Carryforward Expiration Period				20 years
General Business Tax Credit Carryforward [Member]
Tax Credit Carryforward Expiration Period					20 years
Minimum [Member] | Investment Tax Credit Carryforward [Member]
Tax Credit Carryforward Expiration Year				2022
Minimum [Member] | General Business Tax Credit Carryforward [Member]
Tax Credit Carryforward Expiration Year					2026
Maximum [Member] | Investment Tax Credit Carryforward [Member]
Tax Credit Carryforward Expiration Year				2024
Maximum [Member] | General Business Tax Credit Carryforward [Member]
Tax Credit Carryforward Expiration Year					2036
Deferred Tax Assets, Tax Credit Carryforwards, General Business			82,500	$ 82,500
Domestic Tax Authority [Member]
Operating Loss Carryforwards			299,600	$ 299,600
Domestic Tax Authority [Member] | Placed in Service before December 2016 [Member]
Effective Income Tax Rate Reconciliation, Tax Credit, Investment, Percent				30.00%
Domestic Tax Authority [Member] | Placed in Service after December 2016 [Member]
Effective Income Tax Rate Reconciliation, Tax Credit, Investment, Percent				10.00%
Domestic Tax Authority [Member] | Minimum [Member]
Tax Credit Carryforward Expiration Year				2029
Domestic Tax Authority [Member] | Maximum [Member]
Tax Credit Carryforward Expiration Year				2036
State and Local Jurisdiction [Member]
Operating Loss Carryforwards			244,700	$ 244,700
State and Local Jurisdiction [Member] | Earliest Tax Year [Member]
Open Tax Year				2002
State and Local Jurisdiction [Member] | Latest Tax Year [Member]
Open Tax Year				2016
State and Local Jurisdiction [Member] | Minimum [Member]
Tax Credit Carryforward Expiration Year				2018
State and Local Jurisdiction [Member] | Maximum [Member]
Tax Credit Carryforward Expiration Year				2036
Internal Revenue Service (IRS) [Member] | Earliest Tax Year [Member]
Open Tax Year				2000
Internal Revenue Service (IRS) [Member] | Latest Tax Year [Member]
Open Tax Year				2016
Foreign Tax Authority [Member] | Tax Authority of Guatemala in Guatemala [Member]
National Corporate Tax Rate				25.00%
Effective Income Tax Rate				0.00%
Tax Exemption Period				10 years
Effective Income Tax Rate Reconciliation, Tax Exempt Income, Amount				$ 3,300	$ 3,600	$ 1,900
Income Tax Benefit From Examination Per Share | shares				0.07	0.08	0.04
Foreign Tax Authority [Member] | Israel Tax Authority [Member]
National Corporate Tax Rate				25.00%	26.50%	26.50%	25.00%	25.00%
Foreign Tax Authority [Member] | Kenya Revenue Authority [Member]
National Corporate Tax Rate				37.50%
Investment Deduction Percentage		150.00%
Income Tax Examination, Estimate of Possible Loss		$ 16,100
Other Tax Expense (Benefit)					$ 49,400
Foreign Tax Authority [Member] | Kenya Revenue Authority [Member] | Reduction of Income Tax Expense and Deferred Liabilities Due to Overstatement of Tax Position [Member]
Current Period Reclassification Adjustment			$ 4,700
Foreign Tax Authority [Member] | Inland Revenue Department, New Zealand [Member]
National Corporate Tax Rate					28.00%	28.00%	28.00%
Foreign Tax Authority [Member] | Ormat Systems Ltd [Member] | Israel Tax Authority [Member]
Effective Income Tax Rate, Year One									15.00%
Effective Income Tax Rate, Year Three							12.50%
Effective Income Tax Rate, Year Four and Thereafter						16.00%
Effective Income Tax Rate, Year Two								15.00%
Foreign Tax Authority [Member] | Ormat Systems Ltd [Member] | Israel Tax Authority [Member] | Investment One [Member]
Income Tax Incentive Period										5 years
Period For Tax Exemption										2 years
Foreign Tax Authority [Member] | Minimum [Member] | Kenya Revenue Authority [Member]
Tax Losses Carryforward Period		5 years
Foreign Tax Authority [Member] | Maximum [Member] | Kenya Revenue Authority [Member]
Tax Losses Carryforward Period		10 years
Foreign Tax Authority [Member] | Maximum [Member] | Ormat Systems Ltd [Member] | Israel Tax Authority [Member] | Investment One [Member]
Effective Income Tax Rate										25.00%

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Note 19 - Income Taxes - Income From Continuing Operations Before Income Taxes and Equity in Income (Losses) of Investees (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
U.S									$ (7,109)	$ (236)	$ (2,623)
Non-U.S. (foreign)									148,197	113,835	88,459
	$ 36,683	$ 29,047	$ 33,967	$ 41,391	$ 36,202	$ 38,583	$ 22,313	$ 16,501	$ 141,088	$ 113,599	$ 85,836

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Note 19 - Income Taxes - Components of Income Tax Provision (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Federal										$ 51
State									(276)	252	490
Foreign									14,040	19,175	13,983
									13,764	19,478	14,473
Foreign									18,073	(34,736)	13,135
									18,073	(34,736)	13,135
	$ 2,450	$ 11,988	$ 7,890	$ 9,509	$ 11,438	$ (38,211)	$ 6,056	$ 5,459	$ 31,837	$ (15,258)	$ 27,608

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Note 19 - Income Taxes - Significant Components of Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other deferred tax expense (exclusive of the effect of other components listed below)	$ (1,105)	$ 541	$ (18,424)
Usage (benefit) of operating loss carryforwards - U.S.	(14,072)	(30,596)	7,764
Change in valuation allowance	16,411	(14,324)	3,526
Change in foreign valuation allowance		(49,701)
Change in foreign income tax	18,073	14,965	13,135
Change in lease transaction		(452)	2,136
Change in tax monetization transaction	48,000	16,386	5,184
Change in depreciation	(55,462)	28,370	9,431
Change in intangible drilling costs	10,227	10,335	(9,706)
Change in production tax credits and alternative minimum tax credit	(11,659)	610	89
Basis difference in partnership interests	7,660	(10,870)
	$ 18,073	$ (34,736)	$ 13,135

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Note 19 - Income Taxes - Difference Between US Federal Statutory Tax Rate and Company's Effective Tax Rate (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
U.S. federal statutory tax rate	35.00%	35.00%	35.00%
Tax monetization			2.50%
State income tax, net of federal benefit	(0.20%)	0.60%	(0.70%)
Effect of foreign income tax, net	(14.10%)	(5.10%)	(4.90%)
Production tax credits	(8.30%)	(0.10%)	0.90%
Subpart F income	0.30%	1.30%	1.40%
Depletion			(1.10%)
Other, net	(1.30%)		0.80%
Effective tax rate	22.50%	(13.50%)	32.20%
Domestic Tax Authority [Member]
Valuation allowance	11.10%	(1.40%)	(1.70%)
Foreign Tax Authority [Member]
Valuation allowance		(43.80%)

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Note 19 - Income Taxes - Net Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net foreign deferred taxes, primarily depreciation	$ (35,382)	$ (32,654)
Depreciation	148,419	87,943
Intangible drilling costs	(112,762)	(102,013)
Net capital loss carryforward - U.S.	117,924	103,850
Tax monetization transaction	(105,789)	(80,478)
Investment tax credits	1,341	1,341
Production tax credits	82,451	70,792
Stock options amortization	3,241	3,467
Basis difference in partnership interest	(24,462)	(16,801)
Accrued liabilities and other	(752)	2,435
	74,229	37,882
Less - valuation allowance	(109,611)	(70,536)	$ (111,280)	$ (114,806)
Total	$ (35,382)	$ (32,654)	$ (66,943)

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Note 19 - Income Taxes - Reconciliation of Beginning and Ending Valuation Allowance (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Balance at beginning of the year	$ 70,536	$ 111,280	$ 114,806
Additions to (release of) valuation allowance	39,075	(40,744)	(3,526)
Balance at end of the year	$ 109,611	$ 70,536	$ 111,280

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Note 19 - Income Taxes - Balance Sheet Presentation of Deferred Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current deferred tax assets			$ 251
Current deferred tax liabilities			(975)
Non-current deferred tax liabilities	$ (35,382)	$ (32,654)	(66,219)
Total	$ (35,382)	$ (32,654)	$ (66,943)

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Note 19 - Income Taxes - Reconciliation of Beginning and Ending Amounts of Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Balance at beginning of year	$ 10,385	$ 7,511	$ 4,950
Additions based on tax positions taken in prior years	675	(198)	230
Additions based on tax positions taken in the current year	1,059	4,386	2,980
Reduction based on tax positions taken in prior years	(6,381)	(1,314)	(649)
Balance at end of year	$ 5,738	$ 10,385	$ 7,511

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Note 19 - Income Taxes - Foreign Subsidiaries Income Tax Years Open to Examination (Details)	12 Months Ended
	Dec. 31, 2016
Earliest Tax Year [Member] | ISRAEL
Countries	2015
Earliest Tax Year [Member] | KENYA
Countries	2001
Earliest Tax Year [Member] | GUATEMALA
Countries	2010
Earliest Tax Year [Member] | PHILIPPINES
Countries	2010
Earliest Tax Year [Member] | NEW ZEALAND
Countries	2011
Latest Tax Year [Member] | ISRAEL
Countries	2016
Latest Tax Year [Member] | KENYA
Countries	2016
Latest Tax Year [Member] | GUATEMALA
Countries	2016
Latest Tax Year [Member] | PHILIPPINES
Countries	2016
Latest Tax Year [Member] | NEW ZEALAND
Countries	2016

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Note 20 - Business Segments (Details Textual)	12 Months Ended
	Dec. 31, 2016
Number of Reportable Segments	2

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Note 20 - Business Segments - Summarized Financial Information Concerning Reportable Segments (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net revenues from external customers		$ 166,519	$ 184,617	$ 159,861	$ 151,594	$ 171,074	$ 162,852	$ 140,487	$ 120,231	$ 662,591	$ 594,644	$ 559,524
Depreciation and amortization expense										105,977	107,206	100,799
Operating income		51,229	$ 48,223	$ 51,887	$ 50,543	49,088	$ 46,479	$ 38,643	$ 29,851	201,882	164,061	143,490
Segment assets at period end	[1]	2,461,569				2,273,982				2,461,569	2,273,982	2,121,556
Expenditures for long-lived assets										151,930	152,450	158,781
Intersegment Eliminations [Member]
Net revenues from external customers										56,075	48,559	44,718
Electricity [Member]
Net revenues from external customers										436,292	375,920	382,301
Depreciation and amortization expense										102,698	103,892	97,826
Operating income										126,828	99,345	90,401
Segment assets at period end	[1]	2,204,444				2,044,346				2,204,444	2,044,346	1,963,486
Expenditures for long-lived assets										147,211	149,666	155,323
Electricity [Member] | Intersegment Eliminations [Member]
Net revenues from external customers
Product Segment [Member]
Net revenues from external customers										226,299	218,724	177,223
Depreciation and amortization expense										3,279	3,314	2,973
Operating income										75,054	64,716	53,089
Segment assets at period end	[1]	$ 257,125				$ 229,636				257,125	229,636	158,070
Expenditures for long-lived assets										4,719	2,784	3,458
Product Segment [Member] | Intersegment Eliminations [Member]
Net revenues from external customers										$ 56,075	$ 48,559	$ 44,718

[1] Including unconsolidated investments

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Note 20 - Business Segments - Reconciling Information Between Reportable Segments and Consolidated Totals (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues									$ 662,591	$ 594,644	$ 559,524
Operating income	$ 51,229	$ 48,223	$ 51,887	$ 50,543	$ 49,088	$ 46,479	$ 38,643	$ 29,851	201,882	164,061	143,490
Interest income	140	266	245	320	191	53	44	9	971	297	312
Interest expense, net	(15,828)	(17,137)	(18,401)	(16,023)	(18,142)	(17,748)	(18,859)	(17,828)	(67,389)	(72,577)	(84,654)
Foreign currency translation and transaction gains (losses)	(2,942)	(222)	(4,332)	1,962	(981)	1,296	(571)	(1,366)	(5,534)	(1,622)	(5,839)
Income attributable to sale of tax benefits	4,123	3,463	4,519	4,398	6,514	8,634	4,731	5,552	16,503	25,431	24,143
Gain from sale of property, plant and equipment											7,628
Other non-operating income (expense), net	(39)	(5,546)	49	191	(468)	(131)	(1,675)	283	(5,345)	(1,991)	756
Income (loss) from continuing operations, before income taxes and equity in income of investees	$ 36,683	$ 29,047	$ 33,967	$ 41,391	$ 36,202	$ 38,583	$ 22,313	$ 16,501	141,088	113,599	85,836
Intersegment Eliminations [Member]
Revenues									56,075	48,559	44,718
Consolidation, Eliminations [Member]
Revenues									$ (56,075)	$ (48,559)	$ (44,718)

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Note 20 - Business Segments - Revenues as Reported in the Geographic Area (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues	$ 662,591	$ 594,644	$ 559,524
UNITED STATES
Revenues	307,025	286,509	293,710
INDONESIA
Revenues	100,856	93,191	38,174
KENYA
Revenues	109,270	86,545	86,074
TURKEY
Revenues	46,270	57,356	86,340
CHILE
Revenues	58,032	34,478
GUATEMALA
Revenues	30,086	27,897	28,439
Other Foreign Countries [Member]
Revenues	$ 11,052	$ 8,668	$ 26,787

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Note 20 - Business Segments - Long Lived Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Long Lived Assets, Geographic Area	$ 1,941,239	$ 1,857,129	$ 1,790,071
UNITED STATES
Long Lived Assets, Geographic Area	1,414,523	1,374,465	1,369,136
KENYA
Long Lived Assets, Geographic Area	327,157	375,257	330,200
Other Foreign Countries [Member]
Long Lived Assets, Geographic Area	$ 199,559	$ 107,407	$ 90,735

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Note 20 - Business Segments - Revenue From Major Customers (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues		$ 662,591	$ 594,644	$ 559,524
Southern California Edison Company [Member]
Revenues	[1]	$ 33,552	$ 56,026	$ 75,803
Percentage of revenues	[1]	5.10%	9.40%	13.50%
Southern California Public Power Authority [Member]
Revenues		$ 67,566	$ 30,947	$ 21,799
Percentage of revenues		10.20%	5.20%	3.90%
Sierra Pacific Power Company And Nevada Power Company [Member]
Revenues	[1],[2]	$ 127,226	$ 115,876	$ 92,580
Percentage of revenues	[1],[2]	19.20%	19.50%	16.50%
Hyundai [Member]
Revenues	[3]	$ 100,856	$ 93,131	$ 38,174
Percentage of revenues	[3]	15.20%	15.70%	6.80%
Kenya Power And Lighting Co LTD [Member]
Revenues	[1]	$ 109,270	$ 86,545	$ 86,074
Percentage of revenues	[1]	16.50%	14.60%	15.40%

[1] Revenues reported in Electricity segment.

[2] Subsidiaries of NV Energy, Inc.

[3] Revenues related to the Sarulla project that are reported in Products segment.

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Note 21 - Transactions with Related Entities (Details Textual) - USD ($)			1 Months Ended	12 Months Ended
	Feb. 12, 2015	Apr. 01, 2009	Jul. 31, 2004	Dec. 31, 2016	Dec. 31, 2015	Feb. 11, 2015	Dec. 31, 2014
Due from Officers or Stockholders, Current					$ 0		$ 1,337,000
Common Stock, Shares, Outstanding				49,667,340	49,107,901
Corporate Costs And Other				$ 10,000
Other Research and Development Expense, Percentage				10.00%
Lessor Leasing Arrangements, Operating Leases, Term of Contract			25 years
Ormat Systems Ltd [Member]
Operating Lease, Monthly Rent		$ 77,000	$ 52,000
Ormat Industries Ltd. [Member]
Percentage of Public Float Before Transition to Noncontrolled Public Company						40.00%
Percentage of Public Float After Transition to Noncontrolled Public Company	76.00%
Share Exchange Shares Granted Per Share	0.2592
Conversion of Stock, Shares Issued	30,200,000
Stock Issued During Period, Shares, New Issues	3,000,000
Common Stock, Shares, Outstanding	48,500,000					45,500,000
Sale of Stock, Consideration Received on Transaction	$ 15,400,000
Ormat Industries Ltd. [Member] | Shares Issued to Self, Deducted [Member]
Conversion of Stock, Shares Issued	27,200,000
Ormat Industries Ltd. [Member] | Sale of Stock, Other Assets Received [Member]
Sale of Stock, Consideration Received Per Transaction	$ 600,000
Ormat Industries Ltd. [Member] | Sale of Stock, Land and Buildings Received [Member]
Sale of Stock, Consideration Received Per Transaction	12,100,000
Ormat Industries Ltd. [Member] | Sale of Stock, Liabilities Assumed [Member]
Sale of Stock, Consideration Received Per Transaction	$ 500,000
London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument, Basis Spread on Variable Rate					1.00%
Israeli Consumer Price Index [Member] | Minimum [Member]
Debt Instrument, Basis Spread on Variable Rate					4.00%

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Note 21 - Transactions with Related Entities - Summary of Transactions Between Company and Related Entities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property rental fee expense paid to the Parent		$ 303	$ 1,821
Corporate financial, administrative, executive services, and research and development services provided to the Parent		148	148
Services rendered by an indirect shareholder of the Parent		$ 15	$ 51

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Note 22 - Employee Benefit Plan (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	60.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	3.00%	2.00%	2.00%
Defined Contribution Plan, Employer Discretionary Contribution Amount	$ 1,000	$ 600	$ 500
Deposits And Other Assets Noncurrent	18,553	17,968
Severance Costs	2,300	2,500	2,100
Gain (Loss) Of Severance Fund	300	100	$ (1,500)
Israeli Severance Funds [Member]
Deposits And Other Assets Noncurrent	$ 12,800	$ 14,200

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Note 22 - Employee Benefit Plan - Expected Future Benefit Payments (Details) $ in Thousands	Dec. 31, 2016 USD ($)
2017	$ 1,867
2018	2,497
2019	1,655
2020	1,119
2021	1,400
2022	5,141
	$ 13,679

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Note 23 - Commitments and Contingencies (Details Textual) - USD ($)				1 Months Ended	12 Months Ended
	Oct. 26, 2016	Mar. 29, 2016	May 21, 2014	Jan. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2003
Royalty Expense					$ 0	$ 0	$ 0
Letters of Credit Outstanding, Amount					341,600,000
Letter Of Credit Fair Value Disclosure					0
Recorded Unconditional Purchase Obligation					108,100,000
Royalty Cap Amount					1,800,000	1,700,000
Royalty Cap Amount LIBOR Rate					800,000	800,000
Operating Leases, Rent Expense					400,000	$ 400,000	300,000
Capital Leased Assets, Gross					6,900,000
Capital Lease, Period of Payments						5 years
Tax Abatement, Period			20 years
McGinness Plant[Member]
Tax Abatement Benefit, Value			$ 18,600,000
Tuscorura Plant [Member]
Tax Abatement Benefit, Value			$ 6,200,000
Two Former Employees Vs. Ormat [Member] | Settled Litigation [Member]
Loss Contingency, Damages Sought, Value				$ 375,000,000
Payments for Legal Settlements	$ 11,000,000
Two Former Employees Vs. Ormat [Member] | Settled Litigation [Member] | General and Administrative Expense [Member]
Litigation Settlement, Amount					11,000,000
Former Local Sales Representative vs. Ormat [Member] | Pending Litigation [Member]
Loss Contingency, Damages Sought, Value		$ 4,600,000
Loss Contingency, Additional Damages Sought for Ormat Geothermal Products Sales in Chile, Percent		3.75%
Loss Contingency, Damages Sought, Ormat Geothermal Products Sales in Chile, Period		10 years
Minimum [Member]
Percentage For Royalty To Be Paid								3.50%
Maximum [Member]
Percentage For Royalty To Be Paid								5.00%
Construction In Process [Member]
Recorded Unconditional Purchase Obligation					51,000,000
Geothermal Resource Agreement [Member]
Royalty Expense					$ 17,100,000	$ 15,400,000	$ 16,300,000

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Note 24 - Quarterly Financial Information (Unaudited) - Quarterly Financial Information (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Electricity	$ 114,628	$ 109,795	$ 104,001	$ 107,868	$ 97,796	$ 97,245	$ 90,926	$ 89,953	$ 436,292	$ 375,920	$ 382,301
Product	51,891	74,822	55,860	43,726	73,278	65,607	49,561	30,278	226,299	218,724	177,223
Total revenues	166,519	184,617	159,861	151,594	171,074	162,852	140,487	120,231	662,591	594,644	559,524
Cost of revenues:
Electricity	69,163	66,481	62,243	63,686	63,008	61,501	62,522	55,581	261,573	242,612	246,630
Product	30,719	43,647	31,822	24,035	43,927	42,019	27,182	20,625	130,223	133,753	109,143
Total cost of revenues	99,882	110,128	94,065	87,721	106,935	103,520	89,704	76,206	391,796	376,365	355,773
Gross profit	66,637	74,489	65,796	63,873	64,139	59,332	50,783	44,025	270,795	218,279	203,751
Operating expenses:
Research and development expenses	732	1,086	595	349	668	335	414	363	2,762	1,780	783
Selling and marketing expenses	4,288	4,793	3,668	3,675	3,978	4,383	4,283	3,433	16,424	16,077	15,425
General and administrative expenses	10,085	19,093	8,783	8,749	9,185	7,950	7,443	10,204	46,710	34,782	28,614
Write-off of unsuccessful exploration activities	303	1,294	863	557	1,220	185		174	3,017	1,579	15,439
Operating income	51,229	48,223	51,887	50,543	49,088	46,479	38,643	29,851	201,882	164,061	143,490
Interest income	140	266	245	320	191	53	44	9	971	297	312
Interest expense, net	(15,828)	(17,137)	(18,401)	(16,023)	(18,142)	(17,748)	(18,859)	(17,828)	(67,389)	(72,577)	(84,654)
Foreign currency translation and transaction gains (losses)	(2,942)	(222)	(4,332)	1,962	(981)	1,296	(571)	(1,366)	(5,534)	(1,622)	(5,839)
Income attributable to sale of tax benefits	4,123	3,463	4,519	4,398	6,514	8,634	4,731	5,552	16,503	25,431	24,143
Other non-operating income (expense), net	(39)	(5,546)	49	191	(468)	(131)	(1,675)	283	(5,345)	(1,991)	756
Income (loss) from continuing operations, before income taxes and equity in income of investees	36,683	29,047	33,967	41,391	36,202	38,583	22,313	16,501	141,088	113,599	85,836
Income tax benefit (provision)	(2,450)	(11,988)	(7,890)	(9,509)	(11,438)	38,211	(6,056)	(5,459)	(31,837)	15,258	(27,608)
Equity in income (losses) of investees	(3,001)	(2,653)	(1,144)	(937)	(616)	(3,133)	(984)	(775)	(7,735)	(5,508)	(3,213)
Net income (loss)	31,232	14,406	24,933	30,945	24,148	73,661	15,273	10,267	101,516	123,349	55,015
Net loss (income) attributable to noncontrolling interest	(3,002)	(2,326)	(584)	(1,674)	(1,160)	(1,522)	(859)	(235)	7,586	3,776	833
Net income (loss) attributable to the Company's stockholders	$ 28,230	$ 12,080	$ 24,349	$ 29,271	$ 22,988	$ 72,139	$ 14,414	$ 10,032	$ 93,930	$ 119,573	$ 54,182
Net income (in dollars per share)	$ 0.57	$ 0.24	$ 0.49	$ 0.60	$ 0.47	$ 1.47	$ 0.29	$ 0.21	$ 1.90	$ 2.46	$ 1.19
Net income (in dollars per share)	$ 0.56	$ 0.24	$ 0.49	$ 0.59	$ 0.46	$ 1.41	$ 0.28	$ 0.21	$ 1.87	$ 2.43	$ 1.18
Basic (in shares)	49,647	49,599	49,456	49,173	49,074	49,023	48,881	47,244	49,469	48,562	45,508
Diluted (in shares)	50,293	50,289	50,137	49,782	49,668	51,113	50,600	48,079	50,140	49,187	45,859

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Note 25 - Subsequent Events (Details Textual) - USD ($)		12 Months Ended
	Feb. 28, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Dividends, Common Stock		$ 25,682,000	$ 12,716,000	$ 9,555,000
Common Stock, Dividends, Per Share, Declared		$ 0.52	$ 0.26	$ 0.21
Subsequent Event [Member]
Dividends, Common Stock	$ 8.40
Common Stock, Dividends, Per Share, Declared	$ 0.17