Edgar Filing: ORMAT TECHNOLOGIES, INC.

Form 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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 þ

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 þ

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 þ 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 þ 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 þ	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 þ

As of June 30, 2012, 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 $389,817,905 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 28, 2013, the number of outstanding shares of common stock, par value $0.001 per share was 45,430,886.

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, 2012.

ORMAT TECHNOLOGIES, INC.

FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2012

TABLE OF CONTENTS


		Page No

	PART I
ITEM 1.	BUSINESS	10
ITEM 1A.	RISK FACTORS	72
ITEM 1B.	UNRESOLVED STAFF COMMENTS	90
ITEM 2.	PROPERTIES	90
ITEM 3.	LEGAL PROCEEDINGS	90
ITEM 4.	MINE SAFETY DISCLOSURES	93

	PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	94
ITEM 6.	SELECTED FINANCIAL DATA	96
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	97
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	133
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	134
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	201
ITEM 9A.	CONTROLS AND PROCEDURES	201
ITEM 9B.	OTHER INFORMATION	201

	PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	202
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 IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	207
SIGNATURES		208

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		Initial $42,000,000 in aggregate principal amount borrowed by our subsidiary Ortitlan from TCW Global Project Fund II, Ltd.

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.

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

CDC		Commonwealth Development Corporation

CGC		Crump Geothermal Company LLC

CNE		National Energy Commission of Nicaragua

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

DEG		Deutsche Investitions-und Entwicklungsgesellschaft mbH

DFIs		Development Finance Institutions

DISNORTE		Empresa Distribudora de Electricidad del Norte (a Nicaragua distribution company)


Term		Definition

DISSUR		Empresa Distribudora de Electricidad del Sur (a Nicaragua distribution company)

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

EGS		Enhanced Geothermal Systems

EIS		Environmental Impact Statement

ENATREL		Empresa Nicaragüense de Transmision

ENEE		Empresa Nacional de Energía Eléctrica

ENEL		Empresa Nicaragüense de Electricidad

Enthalpy		The total energy control 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.

EPA		U.S. Environmental Protection Agency

EPC		Engineering, procurement and construction

EPS		Earnings per share

ERC		Kenyan Energy Regulatory Commission

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

FPA		U.S. Federal Power Act, as amended

GAAP		Generally accepted accounting principles

GDC		Geothermal Development Company

GDL		Geothermal Development Limited

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


Term		Definition

INE		Nicaragua Institute of Energy

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

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

LNG		Liquefied natural gas

Mammoth Pacific		Mammoth-Pacific, L.P.

MACRS		Modified Accelerated Cost Recovery System

MIGA		Multilateral Investment Guaranty 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 power produced

NBPL		Northern Border Pipe Line Company

NIS		New Israeli Shekel

NGI		Natural Gas-California SoCal-NGI Natural Gas price index

NGP		Nevada Geothermal Power

NV Energy		NV Energy, Inc.

NYSE		New York Stock Exchange

OEC		Ormat Energy Converter

OFC		Ormat Funding Corp., a wholly owned subsidiary of the Company

OFC Senior Secured Notes		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		Senior Secured Notes, due 2034 issued by OFC 2

Olkaria Loan		Initial $105,000,000 in aggregate principal amount borrowed by OrPower 4 from a group of European DFIs


Term		Definition

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		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

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

Orzunil		Orzunil I de Electricidad, Limitada, a wholly owned subsidiary of the Company

Parent		Ormat Industries Ltd.

PG&E		Pacific Gas and Electric Company

PGV		Puna Geothermal Venture, a wholly owned subsidiary of the Company

PLN		PT Perusahaan Listrik Negara


Term		Definition

Power plant equipment		Interconnection equipment, cooling towers for water cooled power plant, etc.

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

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

SOX Act		Sarbanes-Oxley Act of 2002

Solar PV		Solar photovoltaic

Southern California Edison		Southern California Edison Company

SPE(s)		Special purpose entity(ies)

SRAC		Short Run Avoided Costs

Sunday Energy		Sunday Energy Ltd.

TGL		Tikitere Geothermal Power Limited

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

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 1A — “Risk Factors” contained in Part I, Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in Part II, 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;

•

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;

•

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

•

contract counterparty risk;

•

weather and other natural phenomena including earthquakes and other nature disasters;

•

the impact of recent and future federal, state and local regulatory proceedings and changes, including legislative and regulatory initiatives regarding deregulation and restructuring 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;

•

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 existing 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 resulting from the threat or occurrence of 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;

•

development and construction of the Solar PV projects 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 primarily engaged in the geothermal and recovered energy power business. We design, develop, build, 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 all of our recovered energy-based plants have been constructed by us. We conduct our business activities in the following two business segments:

•

The Electricity Segment — in this segment we develop, build, own and operate geothermal and recovered energy-based power plants in the United States and geothermal power plants in other countries around the world and sell the electricity they generate. We have expanded our activities in the Electricity Segment to include the ownership and operation of power plants that produce electricity generated by Solar PV systems that we do not manufacture; and

•

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

The map below shows our current worldwide portfolio of operating geothermal power plants and recovered energy plants and the geothermal, recovered energy-based and Solar PV power plants that are under construction.

LOGO

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, 2012. 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, 2011 and 2012:

LOGO

The following chart sets forth the geographical breakdown of the revenues attributable to our Electricity and Product Segments for each of the years ended December 31, 2011 and 2012:

LOGO

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. 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 represents 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.

We have expanded our activity to the Solar PV industry. We are constructing a new Solar PV project near our Heber complex in California that we expect to come on-line at the end of 2013. In recent years we did development work on Solar PV projects in Israel, but the recent reduction of the feed-in tariff in Israel reduced the potential economic viability of Solar PV projects in Israel and therefore we are evaluating the continued development of some of these projects.

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.

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 as of February 15, 2013. The generating capacity of certain of our power plants listed below has been updated to reflect changes in the resource temperature and other factors that impact resource capabilities:


Power Plant	Location	Ownership⁽¹⁾			Generating Capacity in MW⁽²⁾
Domestic
Geothermal
Brady Complex⁽³⁾	Nevada		100	%		20.0
Heber Complex⁽⁴⁾	California		100	%		92.0
Jersey Valley⁽⁵⁾	Nevada		100	%		12.0
Mammoth Complex⁽⁶⁾	California		100	%		29.0
McGinness Hills⁽⁷⁾	Nevada		100	%		33.0
North Brawley⁽⁸⁾	California		100	%		27.0
Ormesa Complex	California		100	%		54.0
Puna Complex	Hawaii		100	%		38.0
Steamboat Complex⁽³⁾	Nevada		100	%		83.0
Tuscarora	Nevada		100	%		18.0
REG
OREG 1	North and South Dakota		100	%		22.0
OREG 2	Montana, North Dakota and Minnesota		100	%		22.0
OREG 3	Minnesota		100	%		5.5
OREG 4⁽⁹⁾	Colorado		100	%		3.5

Total for domestic power plants						459.0

Foreign
Geothermal
Amatitlan	Guatemala		100	%		18.0
Momotombo	Nicaragua		100	%		22.0
Olkaria III Complex	Kenya		100	%		52.0
Zunil	Guatemala		100	%		24.0

Total for foreign power plants						116.0

Total for all power plants						575.0

⁽¹⁾

We own and operate all of our power plants other than the Momotombo power plant in Nicaragua, which we do not own but which we control and operate through a concession arrangement with the Nicaraguan government until mid-2014. Financial institutions hold equity interests in two 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; and (ii) ORTP, which owns the Heber complex, the Ormesa complex, the Mammoth complex, the Steamboat 2 and 3 and Burdette (Galena 1) power plants both in our Steamboat complex, and Brady power plant in our Brady complex. In the above table, we show these power plants as being 100% owned because all of the generating capacity is owned by either OPC or ORTP and we control the operation of the power plants. The nature of the equity interests held by the financial institutions is described in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “OPC Transaction” and “ORTP Transaction”.

⁽²⁾

References to generating capacity generally refer to the gross capacity less auxiliary power, in the case of all of our existing domestic and foreign power plants, except for 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, the revenues are calculated based on 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. The Capacity Factor of our operating power plants in 2012, excluding the Jersey Valley power plant, which operates at partial load (see footnote 5), was approximately 88%.

⁽³⁾	The generating capacity of the Brady and Steamboat complexes declined due to a drop in the resource temperature. See “Description of Our Power Plants” below.

⁽⁴⁾	The Heber complex generating capacity takes into account the enhancement work that is currently being conducted. See “Description of Our Power Plants” below.

⁽⁵⁾	The Jersey Valley power plant is not operating at full capacity. Detailed information on the Jersey Valley power plant is provided under “Description of Our Power Plants” below.

⁽⁶⁾	The Mammoth complex generating capacity takes into account the enhancement work that is currently being conducted. See “Description of Our Power Plants” below.

⁽⁷⁾	The McGinness Hills power plant commenced commercial operation on July 1, 2012.

⁽⁸⁾	Following recent developments, detailed under “Description of Our Power Plants” below, we have decided to operate the North Brawley power plant at its current capacity level of approximately 27 MW.

⁽⁹⁾	The OREG 4 power plant is not operating at full capacity as a result of continued low run time of the compressor station that serves as the plant’sheat source, which is resulting in low power generation.

All of the revenues that we currently derive from the sale of electricity are pursuant to long-term PPAs. Approximately 59.6% of our total revenues in the year ended December 31, 2012 from the sale of electricity by our domestic power plants were derived from 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 and development of new power plants and expansion of existing power plants. Our growth plan includes 78 MW in generating capacity from geothermal and Solar PV power plants in the United States and Kenya that are fully released for construction with 62 MW expected to be completed by the end of 2013 and the rest in 2014. In addition, we have several projects under various stages of initial construction and development with a total capacity of up to approximately 167 MW.

We have a substantial land position across 41 sites, mostly in the U.S., that are expected to support future geothermal development, on which we have started or plan to start exploration activity. This land position is comprised of various leases, exploration concessions for geothermal resources and an option to enter into geothermal leases.

Our Product Business (Product Segment)

We design, manufacture and sell products for electricity generation and provide the related services described below. Generally, we manufacture products only against customer orders and do not manufacture products for our own inventory.

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 power plant 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 the same customers described above that we target for the sale of our power units for recovered energy-based power generation. 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 control over the timing and delivery of required equipment and its related costs.

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

History

We were formed as a Delaware corporation in 1994 by Ormat Industries Ltd. (also referred to in this annual report as the “Parent”, “Ormat Industries”, “the parent company”, or “our parent”). 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. Ormat Industries owns approximately 60% of our outstanding common stock.

Industry Background

Geothermal Energy

Most of our power plants in operation produce electricity from geothermal energy. There are several different sources or methods to obtain 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 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 if 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. In addition, because geothermal energy power plants produce weather-independent power 24 hours a day, the variable operating costs are lower.

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 from oil and gas production. In some oil and gas fields, water is produced as a by-product of the oil and gas extraction. When the wells are deep the fluids are often at high temperatures and if the water volume 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 shortly 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 isopentane or isobutene, which is vaporized and is used to drive the turbine. The organic fluid is then condensed in a condenser which may be cooled 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. 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 in the plant, where any remaining water droplets are removed. This produces a stream of dry saturated steam, which drives a 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 through the removal system in order to optimize the performance of the steam turbines. The resulting condensate is used to provide make-up water for the cooling tower. The hot brine remaining after separation of steam is injected back into the geothermal resource through a series of injection wells. The flash technology is depicted in the diagram below.

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

Ormat’s Proprietary Technology

Our proprietary technology may be used in power plants operating according to the Organic Rankine Cycle, either 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 computerized fluid dynamics 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 examining ways to increase the output of our plants by utilizing evaporative cooling, cold reinjection, performance simulation programs, and topping turbines. In the geothermal as well as the recovered energy (waste heat) areas, we are examining two-level and three-level energy systems and new motive fluids.

We also developed, patented and construct Geothermal Combined Cycle (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.

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In the conversion of geothermal energy into electricity, our technology has a number of advantages compared with conventional geothermal steam turbine plants. A conventional geothermal steam turbine plant consumes significant quantities of water, causing depletion of the aquifer, and also requires 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 and easy maintenance, low RPM, temperature and pressure in the OEC, a high efficiency turbine and the fact that there is no contact between the turbine itself and often corrosive geothermal fluids.

We use the same elements of our technology in our recovered energy products. The heat source may be exhaust gases from a simple cycle gas turbine, low pressure steam, or medium temperature liquid found in the process industries such as refineries and cement plants. In most cases, we attach an additional heat exchanger in which we circulate thermal oil 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 the OEC 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 exhibit, requires no water treatment (since it is air cooled), and does not require the continuous presence of a licensed steam boiler operator on site.

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

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Patents

We have been granted 82 U.S. patents (and have approximately 28 U.S. patents pending) that 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. The system-related patents cover not only a particular component but also the overall energy conversion system from the “fuel supply” (e.g., geothermal fluid, waste heat, biomass or solar) to electricity production.

They also cover the subjects such as waste heat recovery related to gas pipelines compressors, disposal of non-condensable gases present in geothermal fluids, power plants for very high pressure geothermal resources, and use of two-phase fluids as well as processes related to EGS. A number of 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 terms of our patents range from one year to 17 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 of new EGS technologies and their application to increase the fluid supply at our existing plants by enhancing production of existing wells without drilling any additional wells. We are undertaking this development effort at our Desert Peak 2 and Brady power plants in Nevada in cooperation with GeothermEx Inc., and a number of universities and national laboratories, with funding support from the DOE. Other research and development activity co-funded by the DOE includes testing of new exploration technologies.

We are also continuing with our research and development activities intended to improve plant performance, reduce costs, and increase the breadth of product offerings. The primary focus of our research and development efforts includes continued improvements to our condensing equipment with improved performance and lower land usage and developing new turbines and specialized remote power units.

Additionally, we are continuing to evaluate investment opportunities in new companies with product offerings for renewable energy markets.

Market Opportunity

Interest in geothermal energy in the United States remains strong as a result of legislative and regulatory support for renewable energy, and the baseload nature of geothermal energy generation. We believe that the legislative measures and initiatives discussed below present a significant market opportunity for us.

Although electricity generation from geothermal resources is currently concentrated mainly in California, Nevada, Hawaii, Idaho and Utah, we believe there are opportunities for development in other states such as Alaska, Arizona, New Mexico, Washington and Oregon due to the potential of geothermal resources and, in some cases, a favorable regulatory environment in such states.

The Western Governors Association estimated in 2006 that 13,000 MW of identified geothermal resources will be developed by 2025. In a report issued in April 2012, the Geothermal Energy Association identified a total of 147 confirmed and unconfirmed geothermal projects under various phases of consideration or development in 15 U.S. states that have between 5,317 MW and 5,836 MW potential capacity.

The assessments conducted by the Western Governors Association and the Geothermal Energy Association are estimates only. We refer to them only as two possible reference points, but we do not necessarily concur with those estimates.

An additional factor fueling recent growth in the renewable energy industry is the global concern about the environment. Power plants that use fossil fuels generate higher levels of air pollution and their emissions have been linked to acid rain and global warming. In response to an increasing demand for “green” energy, many countries have adopted legislation requiring, and providing incentives for, electric utilities to sell electricity generated from renewable energy sources. In the United States, approximately 40 states have adopted RPS, renewable portfolio goals, or similar laws requiring or encouraging electric utilities in such states to generate or buy a certain percentage of their electricity from renewable energy sources or recovered heat sources.

According to the Database of State Incentives for Renewables and Efficiency (DSIRE), 22 states (including California, Nevada, and Hawaii, where we have been the most active in our geothermal energy development and in which all of our U.S. geothermal power plants in operation are located) and the District of Colombia define geothermal resources as “renewable”. In addition, according to the EPA, 23 states have enacted RPS or Alternative Portfolio Standards program guidelines that include some form of combined heat and power and/or waste heat recovery.

We expect that the additional demand for renewable energy from utilities in states with RPS will outpace a possible reduction in general demand for energy (if any) due to the effect of general economic conditions. We see this increased demand and, in particular, the impact of the RPS legislation and the increase in California’s RPS to 33% by 2020, as the most significant driver for us to expand existing power plants and to build new projects. California’s three large investor-owned utilities collectively served 19.9% of their 2012 retail electricity sales with renewable power. On July 31, 2012, the CPUC issued its renewable energy progress report for the first/second quarters of 2012, which showed that the state’s utilities have met the goal of serving 20% of their electricity with renewable energy and are on track to surpass that goal in 2012. These utilities have interim targets each year, with a requirement of 25% by 2016 increasing by 2% every year to 33% by the end of 2020. Publicly-owned utilities in California are required to procure 33% of retail electricity sales from eligible renewable energy resources by 2020, opening up a new market of potential off-takers for us. These utilities do not have interim targets. Nevada’s RPS requires NV Energy to supply at least 25% of the total electricity it sells from eligible renewable energy resources by 2025. In 2011, 18.9% of the electricity retail sales in Nevada were from renewable energy sources. Hawaii’s RPS require each electric utility that sells electricity for consumption in Hawaii to obtain 15% of its net electricity sales from renewable energy sources by December 31, 2015, 20% by December 31, 2020, and 40% by 2030. In 2011, Hawaiian Electric Company and its subsidiaries achieved a consolidated RPS of 24.5%.

In 2006, California passed a state climate change law, AB 32, to reduce GHG emissions to 1990 levels by the end of 2020, and in December 2010, the California Air Resources Board (CARB) approved cap-and-trade regulations to reduce California’s GHG emissions under AB 32. The regulations will set a limit on emissions from sources responsible for emitting 80% of California’s GHGs. On November 14, 2012, CARB held its first auction, and sold allowances at the lowest market clearing price and mandated a reserve price of $10.00 per allowance. On November 19, 2012 the CARB released results from the auction showing a market clearing price of $10.09 for the 2013 allowances period and the reserve price of $10.00 for 2015 allowances. One hundred percent of the available 2013 allowances were sold, while only 14% of the available 2015 allowances were sold. The CARB will continue to hold auctions on a quarterly basis.

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 region and Mid-Atlantic states are part of the RGGI, a regional cap-and-trade system to limit carbon dioxide. The RGGI is the first mandatory, market-based carbon dioxide emissions reduction program in the United States. Under RGGI, the participating states plan to reduce carbon emissions from power plants by 10%, at a rate of 2.5% per year between 2015 and 2018.

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

At the federal level as of 2012, the EPA’s Tailoring Rule sets thresholds for when permitting requirements under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs apply to certain major sources of GHG emissions.

The federal government also encourages production of electricity from geothermal resources through certain tax subsidies. If we start construction of a new geothermal power plant in the U.S. by December 31, 2013, then 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. If we fail to meet the start of construction deadline for such a project, then the 30% credit is reduced to 10%. In lieu of the 30% tax credit (if the project qualifies), we are permitted to claim a tax credit based on the power produced from a geothermal power plant. These production-based credits, which in 2012 were 2.2 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. The owner of the power plant may not claim both the 30% tax credit and the production-based tax credit. Under current tax rules, any unused tax credit has a one-year carry back and a twenty-year carry forward. An alternative to these credits is a cash grant from the U.S. Treasury. However, it is only available for certain power plants placed in service by the end of 2011, or on which construction began in 2009, 2010 or 2011 and that are completed by the end of 2013.

Whether we claim tax credits or a cash grant, we are also permitted to depreciate, or write off, most of the cost of the plant. If we claim the one-time 30% (or 10%) tax credit or receive the Treasury cash grant, our tax basis in the plant that we can recover through depreciation must be reduced by one-half of the tax credit or cash grant; if we claim other tax credits, there is no reduction in the tax basis for depreciation. For projects that we placed into service after September 8, 2010 and before January 1, 2012, a depreciation “bonus” will permit us to write off 100% of the cost of certain equipment that is part of the geothermal power plant in the year the plant is placed into service, if certain requirements are met. For projects that are placed into service after December 31, 2011 and before January 1, 2013, a similar “bonus” will permit us to write off 50% of the cost of that equipment in the year the power plant is placed into service. 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 fully utilized) have a present value equivalent to approximately 30% to 40% of the capital cost of a new power plant.

Operations outside of the United States may be subject to and/or benefit from requirements under the Kyoto Protocol. In November 2012, the United Nations Climate Change Conference was held in Doha, Qatar. The conference encompassed the 18th Conference of the Parties to the United Nations Framework Convention on Climate Change and the 8th meeting of the Parties to the Kyoto Protocol. Countries have successfully launched a new commitment period under the Kyoto Protocol, agreed upon a firm timetable to adopt a universal climate agreement by 2015 and agreed to a path to raise necessary awareness to respond to climate change. They also endorsed the completion of new institutions and agreed to ways and means to deliver scaled-up climate finance and technology to developing countries. The next Conference of the Parties is scheduled to take place in Warsaw, Poland, at the end of 2013. Earlier in 2012, at the Rio+20 Conference, which took place in Rio de Janeiro, Brazil, world leaders, along with thousands of participants from the private sector, NGOs and other groups, came together to discuss how to reduce poverty, advance social equity and ensure environmental protection on an ever-more crowded planet. A total of 193 Member States of the United Nations finalized an agreement that aims to advance action on sustainable development.

Outside of the United States, 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 and have encouraged 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 countries have also adopted active governmental programs designed to encourage clean renewable energy power generation. Several Latin American countries have rural electrification programs and renewable energy programs. For example, in November 2003 Guatemala, where our Zunil and Amatitlan power plants are located, approved a law which created incentives for power generation from renewable energy sources by, 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. In Chile, where we were recently awarded six exploration concessions, the Chilean Renewable Energy Act of 2008 currently requires that 5% of electricity sold come from renewable sources, increasing gradually to 10% by 2024. Another example is New Zealand, where we and our Parent have been actively designing and supplying geothermal power solutions since 1986. The New Zealand government’s policies to fight climate change include a target for GHG emissions reductions of between 10% and 20% below 1990 levels by 2020 and the target of increasing renewable electricity generation to 90% of New Zealand’s total electricity generation by 2025. In Indonesia, the government has implemented policies and regulations intended to accelerate the development of renewable energy and geothermal projects in particular. These include designating approximately 4,000 MW of geothermal projects in its second phase of power acceleration projects to be implemented by 2014, of which the majority is IPP projects and the remaining state utility PLN projects. For the IPP sector, certain regulations for geothermal projects have been implemented providing for incentives such as investment tax credits and accelerated depreciation, and pricing guidelines intended to allow preferential power prices for generators; other regulation are being discussed. In addition, there is a regulation providing feed-in tariffs for small scale renewable energy projects up to 10 MW. On a macro level, the Government of Indonesia committed at the United Nations Climate Change Conference 2009 in Copenhagen to reduce its CO₂ emissions by 26% by 2020, which is intended to be achieved mainly through prevention of deforestation and accelerated renewable energy development.

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.

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 may benefit from the increased attention to energy efficiency. For example, in the United States, the 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 initially targeted the North American market, where we have built over 20 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.

Several states, and to a certain extent, the federal government, have recognized the environmental benefits of recovered energy-based power generation. For example, 13 states currently allow electric utilities to include recovered energy-based power generation in calculating such utilities’ compliance with their mandatory or voluntary RPS. In addition, California recently modified the Self Generation Incentive Program (SGIP), which allows recovered energy-based generation to qualify for a per watt incentive. North Dakota, South Dakota, and the U.S. Department of Agriculture (through the Rural Utilities Service) have approved recovered energy-based power generation units as renewable energy resources, which qualifies recovered energy-based power generators for federally funded, low interest loans. Recovery of waste heat is also considered “environmentally friendly” in the western Canadian provinces. We believe that Europe and other markets worldwide may offer similar opportunities in recovered energy-based power generation.

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 in various regions with a view to developing Solar PV power plants in those locations where we can offer competitively priced power generation.

Competitive Strengths

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

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Contracted Generation. All of the electricity generated by our geothermal power plants is currently sold pursuant to long-term PPAs.

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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 a with competitive advantage over other renewable energy sources, such as wind power, solar power or hydro-electric power (to the extent dependent on precipitation), which cannot serve baseload capacity because of their weather dependence and resulting intermittent nature of these other renewable energy sources.

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Competitive Pricing. Geothermal power plants, while site specific, are economically feasible to develop, construct, own, and operate 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.

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.

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 subsidiary 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.

Highly Experienced Management Team. We have a highly qualified senior management team with extensive experience in the geothermal power sector. Key members of our senior management team have worked in the power industry for most of their careers and average over 25 years of industry experience.

Technological Innovation. We have been granted 82 U.S. patents (and have approximately 28 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 leading manufacturer and provider of products and services related to renewable energy. We intend to implement this strategy through:

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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 and which meet our investment criteria;

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Development and Construction of Recovered Energy Power Plants — establishing a first-to-market leadership position in recovered energy power plants in North America and building on that experience to expand into other markets worldwide;

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Acquisition of New Assets — acquiring from third parties additional geothermal and other renewable assets that meet our investment criteria;

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Manufacturing and Providing Products and Service 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;

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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; and

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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.

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On January 28, 2013, we announced that our wholly owned subsidiary, Ormat Nevada, and JPM entered into a tax equity partnership transaction involving certain geothermal power plants in California and Nevada. As part of the transaction, Ormat Nevada transferred the plants into a new subsidiary, ORTP, and sold an interest in ORTP to JPM. In connection with the closing, JPM paid to Ormat Nevada approximately $35.7 million and will make additional payments to ORTP based on the value of PTCs generated by the portfolio over time that are expected to be made until December 31, 2016 and add up to approximately $8.7 million. See detailed description of the transaction under Item 7 — “Management Discussion and Analysis of Financial Condition and Results of Operations” below.

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On January 23, 2013, we announced that we will record an impairment charge to the North Brawley power plant located in Imperial County, California. We recorded an impairment charge to the North Brawley power plant in the fourth quarter of 2012, in an amount of $229.1 million. The North Brawley power plant was placed in service under its power purchase agreement with Southern California Edison in 2010 and since then has been operating at capacities between 20 MW and 33 MW. Due to recent developments, detailed under “Description of Our Power Plants” below, we have decided to operate the plant at the current capacity level of approximately 27 MW and refrain from additional capital investment to expand the capacity.

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In November 2012, we entered into an agreement with Geotermica Platanares to acquire a late stage development geothermal project in Honduras. The project consists of the rights to a field where exploration work has been conducted in the past and a PPA for up to 35 MW with ENEE, the national utility of Honduras. Upon the fulfillment of certain conditions and the closing of the transaction, we will become the owner of all the project’s assets, including wells, land, the PPA and the necessary permits to develop a geothermal project. Once the well field is fully appraised and the power plant is constructed, we will hold the assets under a BOT structure for approximately 15 years.

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In November 2012, our indirect wholly owned subsidiary, OrPower 4, met the distribution requirements under a finance agreement signed in August 2012 with OPIC, an agency of the United States Governments, for limited-recourse project financing totaling up to $310 million for the Olkaria III geothermal power complex located in Naivasha, Kenya. The OPIC financing is described in detail under Item 7 — “Management Discussion and Analysis of Financial Condition and Results of Operations” below.

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In 2012, we entered into two new PPAs with PG&E under the RAM program in California (discussed below in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “Trends and Uncertainties”) to replace the existing SO#4 PPAs:

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We signed a 20-year PPA that was approved by the CPUC, for the sale of up to 14 MW of energy to be produced from the G3 power plant in the Mammoth complex in California. Subject to final agreement with the current off-taker, Southern California Edison, we expect to start selling the electricity under the new PPA in April 2013.

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We signed a 20-year PPA for the sale of up to 7.5 MW of energy to be produced from the G1 power plant in the Mammoth complex in California. The PPA is subject to the approval of the CPUC and to final agreement with Southern California Edison. We expect to start selling the electricity under the new PPA at the end of 2013.

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Since April 2012, we have entered into several derivatives transactions to reduce our exposure to fluctuations in the price of natural gas and oil under our PPAs with Southern California Edison and under the 25 MW PPA for the Puna complex. These transactions have not been designated as hedge transactions and are marked to market with the corresponding gains or losses recognized within electricity revenues.

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In October 2012, we entered into NGI swap contracts for settlement effective from January 1, 2013 until December 31, 2013. The swap contracts have monthly settlements whereby the difference between the NGI and fixed price of $4.00 per MMbtu will be settled on a cash basis. Under the terms of these contracts, we will make floating rate payments to the bank and receive fixed rate payments from the bank on each settlement date. These swap contracts fix the energy rates under the SO#4 PPAs. The capacity payments under these PPAs remain fixed.

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In September 2012, we entered into European put transactions with two banks for settlement effective from January 1, 2013 until December 31, 2013, pursuant to which we purchased NYMEX Heating Oil and ICE Brent put options. We entered into these transactions because both options had a high correlation with the avoided costs that HELCO uses to calculate the energy rate for the 25 MW PPA for the Puna complex. Under these transactions, we will receive on each settlement date the difference between the strike price and the respective monthly average market price of the relevant commodity. If the strike price is lower than the monthly average market price, no payment will be made. These transactions ensure a minimum on-peak energy rate and the capacity payments under these PPAs remain fixed.

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In July 2012, we entered into a European put transaction with a bank for settlement effective from August 1, 2012, pursuant to which we purchased a natural gas put option for 0.7 million MMbtus that settled against NGI on December 31, 2012. We entered into this transaction in order to reduce our exposure to NGI below $3.19 per MMbtu under our SO#4 PPAs with Southern California Edison. The transaction was settled on December 31, 2012.

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In May 2012, we entered into a European put transaction with a bank for settlement effective from July 1, 2012, pursuant to which we purchased a natural gas put option for 4.4 million MMbtus that settled against NGI on December 31, 2012. We entered into this transaction in order to reduce our exposure to NGI below $3.08 per MMbtu under our California SO#4 PPAs with Southern California Edison. The transaction was settled on December 31, 2012.

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In April 2012, we entered into a NYMEX Heating Oil swap contract (85%) and an ICE Brent swap contract (15%) with a bank, each of which is effective from May 1, 2012 until March 31, 2013. We entered into these contracts because both swaps had a high correlation with the avoided costs that HELCO uses to calculate the energy rate for the 25 MW PPA for the Puna complex. Fuel prices in April 2012 were at historically high levels and we wanted to protect ourselves from a decrease in prices over the next twelve months. The contracts did not have up-front costs. Under the terms of these contracts, we will make floating rate payments to the bank and 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 monthly average price will be settled on a cash basis.

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In the second and third quarters of 2012, we received approximately $119.2 million in cash grants from the U.S. Treasury under Section 1603 of the ARRA for specified energy property in lieu of tax credits relating to the enhancement of our Puna geothermal complex, and to our Jersey Valley, Tuscarora and McGinness Hills geothermal power plants.

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In August 2012, NV Energy approved the commercial operation date of our 33 MW McGinness Hills power plant in Nevada and the full energy price under the PPA has been paid retroactive to July 1, 2012.

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In July 2012, our wholly owned subsidiary, Ormat Nevada, entered into a $61.4 million EPC contract with Enel Green Power. Under the terms of the EPC contract, we will provide two air-cooled Ormat Energy Converters at Enel Green Power’s Cove Fort geothermal power plant project in southern Utah. Previously in April 2012, we entered into an interim agreement in the amount of $9.1 million to ensure timely completion of the project.

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In May 2012, NV Energy approved the commercial operation date of our 18 MW Tuscarora power plant in Nevada and the full energy price under the PPA has been paid retroactive to January 1, 2012.

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In May 2012, Bronicki Investments Ltd. (Bronicki Investments), a shareholder of Ormat Industries, completed the sale of part of its interest in Ormat Industries to FIMI ENRG Limited Partnership, a newly formed Israeli partnership, and FIMI ENRG, L.P., a newly formed Delaware partnership, both controlled by FIMI Opportunity IV (collectively, FIMI), whereby Bronicki Investments sold to FIMI approximately11.7% of the issued and outstanding shares of Ormat Industries. Following consummation of the transaction, each of Bronicki Investments and FIMI held 22.499% of the issued and outstanding shares of Ormat Industries, and the parties collectively owned 44.999% of the issued and outstanding shares of Ormat Industries. In addition, effective May 22, 2012, Gillon Beck, a senior partner in FIMI, was appointed as the Chairman of our Board of Directors; Ami Boehm, David Granot and Robert E. Joyal were appointed to our Board; and Lucien Y. Bronicki (our former Chairman), Roger W. Gale and David Wagener (former members of our Board) resigned from their respective positions on our Board of Directors.

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 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, with the exception of the Puna complex, which is an Exempt Wholesale Generator, 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, particularly in the U.S. and recently also internationally. These activities generally involve:

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Identifying and evaluating potential geothermal resources using information available to us from public and private resources as described under “Initial Evaluation” below.

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Acquisition of land rights to any geothermal resources our initial evaluation indicates could potentially support a commercially viable power plant, taking into account various factors described under “Land Acquisition” below.

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Conducting geophysical and geochemical surveys on some or all of the sites acquired, as described under “Surveys” below.

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Obtaining permits to conduct exploratory drilling, as described under “Environmental Permits” below.

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Drilling one or more exploratory wells on some or all of the sites to confirm and/or define the geothermal resource where indicated by our surveys and creating access roads to drilling locations and related activities, as described under “Exploratory Drilling” below.

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Drilling a full-size well (as described below) if our exploratory drilling indicates the geothermal resource can support a commercially viable power plant taking into account various factors described below under “Exploratory Drilling”. Drilling a full-size well is the point at which we usually consider a site moves from exploration to construction or development.

It normally takes us 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.

Initial Evaluation. As part of our initial evaluation, we generally adhere to the following process, although our process can vary from site to site depending on the particular circumstances involved:

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We evaluate historic, geologic and geothermal information available from public and private databases.

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For some sites, we may obtain and evaluate additional information from other industry participants, such as where oil or gas wells may have been drilled on or near a site.

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

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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 of a site range from approximately $20,000 to $100,000.

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

Land Acquisition. 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 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 United States 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.

Surveys. Following the acquisition of land rights for a potential geothermal resource, we conduct surface water analyses and soil surveys to determine proximity to possible heat flow anomalies and up-flow/permeable zones and augment our digital database with the results of those analyses. We then initiate a suite of geophysical surveys (e.g., gravity, magnetics, resistivity, magnetotellurics, and spectral surveys) to assess surface and sub-surface structure (e.g., faults and fractures) and develop a roadmap of fluid-flow conduits and overall permeability. All pertinent geophysical data are then used to create three-dimensional geothermal reservoir models that are used to identify drill locations.

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 and geophysical surveys. If the results from the geochemical and geophysical surveys are poor (i.e., low derived resource temperatures or poor permeability), we will re-evaluate the commercial viability of the geothermal resource and may not proceed to exploratory drilling.

Exploratory Drilling. If we proceed to exploratory drilling, we generally will use outside contractors to create access roads to drilling sites. In the last two years we concentrated 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 or outside contractors. If the core hole is “cold” or does not support the assumed permeability, it may be capped and the area reclaimed if we conclude that the geothermal resource will not support a commercially viable power plant. 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. However, to reduce construction risk we may also decide to drill a full-size well.

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, among other things. However, on average, exploration drilling costs, excluding drilling of a full-size well, are approximately $3.0 million for each site.

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:

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New information 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.

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

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Anticipated costs associated with further exploration activities.

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

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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.

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

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Drilling production wells.

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

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Obtaining any required permits.

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

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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 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 to maintain the geothermal resource and surface conditions. The production wells are normally drilled by our own drilling equipment although in some cases we use outside contractors.

The cost for each production 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 average costs for each production well is approximately $4.0 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 the year ended December 31, 2012 we focused, in the Electricity Segment, on the construction of the McGinness Hills power plant, and the Wild Rose and Olkaria III Plant 2 projects in order to meet the respective completion deadlines. The uncertainty around future federal support and the temporary weakness in the PPA market in the western United States reduced the number of our projects that were moved to construction in 2012. During the year ended December 31, 2011, one site (Olkaria III Plant 2) moved to construction, and during the year ended December 31, 2010, two sites (CD4 at the Mammoth complex and Wild Rose) moved to construction.

We discontinued exploration activities at five sites in Nevada during the year ended December 31, 2012 and at one site in Nevada during the year ended December 31, 2010. Those sites were Leach Hot springs, Hyder Hot springs, Seven Devil, Smith Creek and Walker River in 2012 and Gabbs Valley in 2010. After conducting exploratory drilling in those sites, we concluded that the geothermal resource would not support commercial operations at this time. Costs associated with exploration activities at these sites were expensed accordingly. No exploration activities were discontinued in 2011 (see “Write-off of Unsuccessful Exploration Activities” under Item 7 — “Management Discussion and Analysis of Financial Condition and Results of Operations”).

Five new sites were added to our exploration and development activities in the year ended December 31, 2012, compared with thirteen sites in the year ended December 31, 2011 and with seven sites in the year ended December 31, 2010.

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. Outside of the United States, 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 called PPAs) for the sale of electricity or the conversion of geothermal resources into electricity. Although a power plant’s revenues under a PPA previously 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.

How We Finance Our Power Plants. Historically we have funded our power plants with a combination of non-recourse or limited recourse debt, lease financing, parent company loans, and internally generated cash, which includes funds from operation, as well as proceeds from loans under corporate credit facilities, sale of securities, and other sources of liquidity. 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.

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 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. To the extent of these limited recourse obligations, creditors of a project financing of a particular power plant may have direct recourse to us.

We have also used financing structures to monetize PTCs and other favorable tax benefits derived from the financed power plants and an operating lease arrangement for one of our power plants.

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 contracts 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 revenue loss 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 all of our foreign power plants in operation.

Description of Our Leases and Lands

We have domestic leases on approximately 403,400 acres of federal, state, and private land in Alaska, California, Hawaii, Idaho, Nevada, New Mexico, Oregon and Utah. The approximate breakdown between federal, state, private leases and owned land is as follows:

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76% are leases with the U.S. government, acting through the BLM;

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13% are leases with private landowners and/or leaseholders;

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9% are leases with various states, none of which is currently material; and

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2% are owned by us.

Each of the leases within each of the categories has standard terms and requirements, as summarized below. Internationally, our land position includes approximately 366,300 acres, most of which are geothermal exploration licenses in six prospects in Chile.

Bureau of Land Management (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).

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 of waste brine and other waste products 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.

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.

Exploration Concessions in Chile

We have been awarded six exploration concessions in Chile, under which we have the rights to start exploration work with an original term of two years. Prior to the last six months of the original term of each exploration concession, we can request its extension for an additional period of two years. According to applicable regulations, the extension of the exploration concession is subject to the receipt by the Ministry of Energy of evidence that at least 25% of the planned investments for the execution of the project, as reflected in the relevant proposal submitted during the tender process, has been invested. Following submission of the request, the Ministry of Energy has three months in which it may grant or deny the extension. As of the date of this report we have received an extension for one of the six concessions.

Description of Our Power Plants

Domestic Power Plants

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

Brady Complex

Location

Churchill County, Nevada

Generating Capacity

20 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 six 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 operations 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 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 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 right of ways from the BLM and from the private owner that allows access to and from the plant.

Resource Information

The resource temperature at Brady is 274 degrees Fahrenheit and at Desert Peak 2 is 370 degrees Fahrenheit.

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 for a distance of 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.

Resource Cooling

Approximately four degrees Fahrenheit per year was observed at Brady during the past 15 years of production. The temperature decline at Desert Peak is less than one degree 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 Brady, and OPC Transaction in the case of Desert Peak 2.

Heber Complex

Location

Heber, Imperial County, California

Generating Capacity

92 MW

Number of Power Plants

Five (Heber 1, Heber 2, Heber South, G-1 and G-2).

Technology

The Heber 1 plant utilizes dual flash and the Heber 2, Heber South, G-1 and G-2 plants utilize binary systems. The complex uses a water cooled system.

Subsurface Improvements

31 production wells and 34 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 G-1 plant commenced commercial operation in 2006 and the G-2 plant in 2005. The Heber South plant commenced commercial operation in 2008.

Land and Mineral Rights

The total Heber area is comprised of mainly 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 348 degrees Fahrenheit. The resource supplying the pumped Heber 2 wells averages 318 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.

Resource Cooling

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

Two PPAs with Southern California Edison and one PPA with SCPPA.

PPA Expiration Date

Heber 1 — 2015, Heber 2 — 2023, and Heber South — 2031. The output from the G-1 and G-2 power plants is sold under the PPAs of Southern California Edison and SCPPA.

Financing

OrCal Senior Secured Notes and ORTP Transaction.

Supplemental Information

As a result of the transition to variable energy rates under the Heber 1 and Heber 2 PPAs and the significant decline in natural gas prices, we have experienced a substantial reduction in 2012 revenues. We expect that once the PPAs are replaced or expired we will be able to secure a rate higher than the current rate.

We have revised our investment plans to optimize the operation of the complex rather than increasing the generating capacity. We plan to add additional wells and replace part of the old equipment with new equipment.

Jersey Valley Power Plant

Location

Pershing County, Nevada

Generating Capacity

12 MW (See supplemental information below)

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 will be used in the future as required. Re-drilling of certain injection wells is currently under development.

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 330 degrees Fahrenheit.

Resource Cooling

Will be established in the future.

Power Purchaser

Nevada Power Company.

PPA Expiration Date

2032

Financing

Corporate funds and ITC cash grant from the U.S. Treasury.

Once the Jersey Valley power plant reaches certain operational targets and meets other conditions precedent we have the ability to borrow additional funds under the OFC 2 Senior Secured Notes.

Supplemental Information

The Jersey Valley power plant is currently operating at 7 MW, below its designed capacity. This is primarily due to the need to shut down one of the injection wells that was rendered unusable by old mining wells that we believe were not adequately plugged when abandoned by the mining operator that previously operated on the land.

We plan to improve injection capacity. We conducted an impairment test and no impairment is required.

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

Eleven production wells and five injection wells connected to the plants through a gathering system.

Major Equipment

Eight Rotoflow expanders together with the Balance of Plant equipment.

Age

The G-1 plant commenced commercial operations in 1984 and G-2 and G-3 commenced commercial operation in 1990.

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”.

We purchased land at Mammoth that was owned by a third party. This purchase will reduce royalty expenses for the Mammoth complex.

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 year the temperature was stabilized and there is no notable decline, although one degree Fahrenheit per year was observed during the prior 20 years of production.

Power Purchaser

Southern California Edison.

PPA Expiration Date

G-1 — 2014, G-2 and G-3 — 2020.

Financing

OFC Senior Secured Notes and ORTP Transaction.

Supplemental Information

As a result of the transition to variable energy rates under the Mammoth complex PPAs and the significant decline in natural gas prices, we have experienced a substantial reduction in 2012 revenues. In 2012, we entered into two new PPAs with PG&E, which will

replace the current G-1 (in April 2013) and G-3 PPAs (at the end of 2013) with Southern California Edison. Once effective, the new PPAs will partially minimize the reduction in revenues.

We have revised our investment plans to optimize the operation of the complex rather than increasing the generating capacity. We plan to replace part of the old units in the Mammoth complex (G-1 and G-3) with new Ormat-manufactured equipment. We recently started the manufacturing of the equipment.

McGinness Hills Power Plant

Location

Lander County, Nevada

Generating Capacity

33 MW

Number of Power Plants

One

Technology

The McGinness Hills power plant utilizes an air cooled binary system.

Subsurface Improvements

Five production wells and three injection wells are connected to the power plant.

Material Equipment

Two air cooled OEC units with the Balance of Plant Equipment.

Age

The power plant commenced commercial operation on July 1, 2012,

Land and Mineral Rights

The McGinness Hills area is comprised of private and BLM leases.

The leases are currently held by the payment of 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 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, 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 337 degrees Fahrenheit and the fluids are sourced from the reservoir at elevations between 2,000 to 5,000 feet below the surface.

The average temperature of the resource is approximately 335 degrees Fahrenheit.

Resource Cooling

Will be established in the future.

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 and ITC cash grant from the U.S. Treasury.

North Brawley Power Plant

Location

Imperial County, California

Generating Capacity

27 MW (See supplemental information below)

Number of Power Plants

One

Technology

The North Brawley power plant utilizes a water- cooled binary system.

Subsurface Improvements

17 production wells and 21 injection wells are currently connected to the plant through a gathering system. An additional injection well was drilled and it is currently being evaluated.

Major Equipment

Five OEC units together with the Balance of Plant equipment.

Age

The power plant was placed in service on January 15, 2010 with commercial operation having commenced on March 31, 2011.

Land and Mineral Rights

The total North 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”.

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

North 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 (1,500 — 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 North Brawley power plant.

The average produced fluid resource temperature is 335 degrees Fahrenheit.

Resource Cooling

Will be established in the future.

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

Since the North Brawley power plant was placed in service, in 2010, it has been much more difficult to operate its geothermal field than other fields and the power plant has been unable to reach its design capacity of 50 MW. Instead, it has been operating at capacities between 20 MW and 33 MW. This generation level has been achieved following significant additional capital expenditures and higher than anticipated operating costs.

We plan to continue to sell the generated power from the North Brawley plant to Southern California Edison under the existing PPA and at the current capacity level of approximately 27 MW and refrain from additional capital investment to expand the capacity.

As noted above, during the fourth quarter of 2012 we recognized an impairment charge of $229.1 million for this plant.

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.

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.

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.

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.

Supplemental Information

The OREG 4 power plant was tested for impairment in the third quarter of 2012 due to continued low run time of the compressor station that serves as its heat source, which resulted in low power generation and revenue.

As a result, during the third quarter of 2012 we recognized an impairment charge of $7.3 million for this plant.

Ormesa Complex

Location

East Mesa, Imperial County, California

Generating Capacity

54 MW

Number of Power Plants

Four (OG I, OG II, GEM 2 and GEM 3)

Technology

The OG plants utilize a binary system and the GEM plants utilize a flash system. The complex uses a water cooling system.

Subsurface Improvements

32 production wells and 52 injection wells connected to the plants through a gathering system.

Material Major Equipment

32 OEC units and two steam turbines with the Balance of Plant equipment.

Age

The various OG I units 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 plants 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 resource temperature is an average of 306 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.

Resource Cooling

One degree Fahrenheit per year was observed during the past 20 years of production.

Sources of Makeup Water

Water is provided by the IID.

Power Purchaser

Southern California Edison under a single PPA.

PPA Expiration Date

2018

Financing

OFC Senior Secured Notes and ORTP Transaction.

Supplemental Information

As a result of the transition to variable energy rates under the Ormesa PPA and the significant decline in natural gas prices, we have experienced a substantial reduction in 2012 revenues. We expect that once the PPAs are replaced or expired we will be able to secure a rate higher than the current rate.

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

Five production wells and four injection wells connected to the plants through a gathering system. We drilled a sixth production well, which is currently under evaluation.

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.

Land and Mineral Rights

The Puna area is comprised of a private lease. The private lease is between PGV and KLP and it expires in 2046. PGV pays 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 3% 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.

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.

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 price has not changed from HELCO avoided cost.

•

For the next on-peak 5 MW, the price has changed from a diesel-based price to a flat rate of 11.8 cents per kWh escalated 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, escalated by 1.5% per year.

•

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:

•

For the first off-peak 5 MW, the price has changed from diesel-based price to a flat rate of 11.8 cents per kWh escalated by 1.5% per year.

•

For the energy above 27 MW (up to 38 MW) the price is 6 cents per kWh, escalated 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

83 MW

Number of Power Plants

Seven (Steamboat 1A, 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

23 production wells and eight injection wells connected to the plants through a gathering system.

Major Equipment

12 individual air cooled OEC units and one steam turbine together with the Balance of Plant Equipment.

Age

The Steamboat 1A plant commenced commercial operation in 1988 and the other 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 and we repowered Steamboat 1A.

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 is an average of 290 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

In the last year the temperature dropped by three degrees Fahrenheit, slightly more than the two degrees per year observed during the prior 20 years of production.

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 1A, Steamboat 2 and 3, Burdette (Galena1), Steamboat Hills, and Galena 3) and Nevada Power Company (for Galena 2).

PPA Expiration Date

Steamboat 1A — 2018, 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 1A, Steamboat 2 and 3, and Burdette (Galena1)) and OPC Transaction (Steamboat Hills, Galena 2, and Galena 3)

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

Four production and five injection wells are connected to the power plant.

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 resource temperature averages 346 degrees Fahrenheit.

Resource Cooling

Will be established in the future.

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 and ITC cash grant from the U.S. Treasury.

Foreign Power Plants

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

Amatitlan Power Plant (Guatemala)

Location

Amatitlan, Guatemala

Generating Capacity

18 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

One steam turbine and two OEC units 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 3% 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 and 2% of revenues exceeding 20.5 MW.

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 528 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 project loan from TCW Global Project Fund II, Ltd.

Supplemental Information

The power plant was registered by the United Nations Framework Convention on Climate Change as a Clean Development Mechanism. It is expected to offset emissions of approximately 83,000 tons of CO₂ per year. The power plant had a contract to sell all of its emission reduction credits through the end of 2012 to a European buyer.

Momotombo Power Plant (Nicaragua)

Location

Momotombo, Nicaragua

Generating Capacity

22 MW

Number of Power Plants

One

Technology

The Momotombo power plant utilizes single flash and binary systems. The plant uses air and water cooled systems.

Subsurface Improvements

Ten production wells and seven injection wells connected to the plants through a gathering system.

Major Equipment

One steam turbine and one OEC unit together with the Balance of Plant equipment.

Age

The plant commenced commercial operation in 1983 and we signed the concession agreement in 1999.

Land and Mineral Rights

The total Momotombo area is under a concession agreement which expires in mid-2014.

We sell the generated electricity at the boundary of the plant. The transmission line is owned by the utility.

Resource Information

The resource temperature is an average of 463 degrees Fahrenheit.

The Momotombo geothermal reservoir is located within sedimentary and andesitic volcanic formations that relate to the Momotombo volcano.

Main flow paths in the geothermal system are a hot reservoir layer. The shallow layer conducted deep fluids that eventually will be discharged at surface at the eastern edge of the geothermal system at the shore of the Lake Managua.

Resource Cooling

Approximately 3.5 degrees Fahrenheit per year was observed during the past ten years of production.

Access to Property

Direct access to public roads and access across the property are provided under surface rights granted pursuant to the concession assignment agreement.

Sources of Makeup Water

Condensed steam is used for makeup water.

Power Purchaser

DISNORTE and DISSUR

PPA Expiration Date

2014

Financing

A loan from Bank Hapoalim B.M, which was repaid in full in 2010.

Olkaria III Complex (Kenya)

Location

Naivasha, Kenya

Generating Capacity

52 MW

Number of Power Plants

Two (Olkaria III Phase 1 and Olkaria III Phase 2, together Plant 1).

Technology

The Olkaria III complex utilizes an air cooled binary system.

Subsurface Improvements

Ten production wells and three injection wells connected to the plants through a gathering system.

Major Equipment

Six OEC units together with the Balance of Plant equipment.

Age

Phase 2 commenced commercial operation in January 2009 and was incorporated into Plant 1, which commenced operation in 2000.

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 resource temperature is an average of 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.

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

2029

Financing

Senior secured project finance loan from OPIC and a subordinated loan from DEG.

Supplemental Information

See “Projects under Construction — Olkaria III Plant 2 and 3 (Kenya)”.

Upon the completion of Plant 2 the expiration date of the PPA will be extended until 2033.

Zunil Power Plant (Guatemala)

Location

Zunil, Guatemala

Generating Capacity

24 MW

Number of Power Plants

One

Technology

The Zunil power plant utilizes an air cooled binary 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 geothermal wells and resource are owned by INDE and are not under our responsibility.

Access to Property

Direct access to public roads.

Power Purchaser

INDE

PPA Expiration Date

2019

Financing

Senior Secured project loan from IFC and CDC that was repaid in full in November 2011.

Supplemental Information

Through August 2011, the energy output of the power plant was sold under a “take or pay” arrangement, under which the revenues were calculated based on 24 MW capacity regardless of the actual performance of the power plant. From September 2011, the energy portion of revenues is paid based on the actual generation of the power plant, while the capacity portion remains the same. The actual generation of the power plant is based on a capacity of approximately 13 MW. In 2012, the energy revenues were approximately 17% of the total revenues of the power plant.

Projects under Construction

We are in varying stages of construction or enhancement of domestic and foreign projects, some of them are fully released for construction and two projects are each in an initial stage of construction.

The following is a description of projects in California, Nevada and Kenya with a total generating capacity of 78 MW that are fully released for construction with 62 MW expected to be completed by the end of 2013 and the rest expected to be completed in 2014.

Heber Solar PV Project (U.S.)

Location

Imperial County, California

Projected Generating Capacity

10 MW (24,500 MWh per year)

Projected Technology

Solar PV.

Condition

Under development.

Land

The Heber Solar area is comprised of land that we own.

Access to Property

Direct access to public roads from the leased property and access across the leased property.

Power Purchaser

The IID

PPA Expiration Date

20 years after date of COD.

Financing

Corporate funds.

Projected Operation

2013

Supplemental Information

Commercial operation is expected in 2013, subject to timely completion of the interconnection that is to be provided by the IID.

Olkaria III – Plant 2&3 (Kenya)

Location

Naivasha, Kenya

Projected Generating Capacity

Plant 2 — 36 MW and Plant 3 — 16MW

Technology

Plants 2 and 3 of the Olkaria III complex will utilize an air cooled binary system.

Condition

Field development of Plant 2 is in its final stage and site construction is close to completion. Plant 3 is in early stage of field development.

Subsurface Improvement

Seven production wells have been drilled.

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.

The expected average temperature of the resource cannot be estimated as field development has not been completed yet.

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

20 years from COD of Plant 2.

Financing

Senior secured project finance loan from OPIC.

Projected Operation

Plant 2 — mid-2013 and Plant 3 — 2014.

Supplemental Information

We amended and restated the existing PPA with KPLC. The amended and restated PPA provides for the construction of a new 36 MW power plant at the Olkaria III complex. The PPA amendment includes an option for additional capacity up to 100 MW.

We have closed a limited-recourse senior secured financing with OPIC. See description in Item 7 under “New Financing of our Projects”.

Wild Rose Project (U.S.)

Location

Mineral County, Nevada

Projected Generating Capacity

16 MW

Projected Technology

The Wild Rose power plant will utilize a binary system.

Material Equipment

Power plant equipment and the Balance of Plant.

Condition

Field development was completed and manufacturing of the power plant equipment is in an advanced stage.

Subsurface Improvement

Five production and three injection wells have been drilled.

Land and Mineral Rights

The Wild Rose 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 September 30, 2017.

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 expected average temperature of the resource is between 260 and 265 degrees Fahrenheit.

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

The PPA for this power plant is in the approval process of the off-taker.

Financing

Corporate funds.

Projected Operation

2013

The following is a description of 50 MW projects in Nevada and California that are in an initial stage of construction:

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

On hold.

Subsurface Improvements

On hold.

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.

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”.

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 new PPA.

Financing

Corporate funds.

Projected Operation

To be determined.

Supplemental Information

Permitting delays have prevented substantial progress on the project site and on transmission until late last year and have had a significant impact on the development plan and the economics of the project. As a result, in December 2011, we terminated the project’s PPA and joint operating agreement with Nevada Power Company.

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

On hold.

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, several of which are held by production and the remainder of which are the subject of a unitization agreement that is pending BLM approval. The expiration date of the leases (assuming approval of the unitization agreement) is after the end of the expected useful life of the power plant.

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 to deliver energy into the Southern California Edison system at the Casa Diablo Substation.

Future Projects

Projects under Various Stages of Development

We also have projects under various stages of development in the United States, Kenya, Honduras, and Indonesia. 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 be up to approximately 117 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 this year.

Crump Geyser Project (U.S.)

In October 2010, we and NGP agreed to jointly develop, construct, own and operate one or more geothermal power plants in the Crump Geyser Area located in Lake County, Oregon. All activities will be carried out through CGC, a limited liability company that is owned equally by our wholly owned subsidiary, Ormat Nevada, and NGP.

We will be the EPC contractor for the project, which will utilize our proprietary generating equipment and other Balance of Plant equipment. We will also be the Operator and provide operating and maintenance services to CGC.

We and NGP intend to build an up to 20 MW power plant, which is expected to be placed in service gradually.

Platanares Project (Honduras)

Upon the fulfillment of certain conditions and the closing of the transaction, we will become the owner of all the project’s assets, including wells, land, the PPA and the necessary permits to develop a geothermal project. Once the well field is fully appraised and the power plant is constructed, we will hold the assets under a BOT structure for approximately 15 years.

Sarulla Project (Indonesia)

We are a member of a consortium which is in the process of developing the Sarulla geothermal power project in Indonesia, of approximately 330 MW. We own 12.75% of the Indonesian special purpose entity that will develop and operate the project.

The Sarulla project, located in Tapanuli Utara, North Sumatra, represents the largest single-contract geothermal power project to date, reflecting the large scale, high productivity and potential of the Indonesian geothermal resources. The project will be owned and operated by the consortium members under the framework of a Joint Operating Contract (JOC) with PT Pertamina Geothermal Energy, and Energy Sales Contract with PT PLN (the state electric utility which is the off-taker of the electricity from the Sarulla Project). The Sarulla combined cycle geothermal power plant is to be constructed in three equal phases over four years. Ormat’s turbines account for about 120 MW of the total expected electricity generation.

The adjustment of the electricity tariff for the 330 MW Sarulla project has already been agreed between PT PLN and the consortium, based on the verification of the agreed tariff by the BPKP (Indonesian State Auditor for Development). The JOC and the Energy Sales Contract (ESC) amendments are currently in their final stage, reflecting the agreed adjusted tariff as well as other financial and bankability conditions which have been agreed in principle by the relevant Indonesian ministries, such as the Ministry of Energy and Mineral Resources and the Ministry of Finance.

Pending resolution of certain bankability issues, the execution of these amended contracts is expected to occur during the first half of 2013.

Sarulla Operations Ltd. (the project company) has received responses from over ten international banks that were invited to submit proposals to provide limited recourse financing for the Sarulla Project. The expected financing package will consist of direct loans from the Japan Bank for International Cooperation (JBIC) and the Asian Development Bank (ADB), in addition to Extended Political Risk Guarantees to the participating commercial banks by JBIC.

Sarulla Operations Ltd. has mandated certain lenders, while the selection and engagement of due diligence consultants is currently underway.

On the execution side, the EPC contractor was selected and a term sheet for the supply contract, at a total value of approximately $254.0 million, was entered by us with the designated EPC contractor.

Although, the consortium already started certain testing and development activities in the site, construction is expected to start after the consortium obtains financing, a process which we expect to take approximately one year from the date of execution of the amended ESC and JOC.

Wister Project (U.S.)

We plan to develop the Wister project on private leases located in Imperial County, California. We expect the first phase of the project to be 30 MW. The project has been awarded an exploration grant of $4.5 million under the DOE’s Innovative Exploration and Drilling Projects program and the exploration activity under this program has started.

Since it became clear that Wister will not be able to meet the PPA milestones we started discussions with the off-taker on a possible cancellation of the PPA.

Exploration 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. Our land position is comprised of various leases and private land for geothermal resources of approximately 272,000 acres in 30 prospects including the following:

Nevada [13]

Argenta

Under exploration studies

Baltazar

Under exploration studies

Beowawe

Under exploration studies.

Dixie Hope

Under exploratory drilling.

Dixie Meadows — Comstock

Completed exploration studies; expected to start exploratory drilling.

Edwards Creek

Under exploratory drilling.

Hycroft

Under exploration studies.

Tungsten Mountain

Under exploratory drilling.

Tuscarora Expansion

Completed exploration studies; awaiting permits to start exploratory drilling.

Wildhorse (Mustang)

Under exploration studies.

Aqua Quieta

Completed exploration studies; expected to start exploratory drilling.

South Jersey

Lease acquired but no further action has yet been taken.

McGinness Hills expansion

Completed exploration studies; expected to start exploratory drilling.

California [2]

East and North Brawley

Deep resource lease acquired but no further action has yet been taken.

Rhyolite Plateau

Lease acquired but no further action has yet been taken.

Hawaii [3]

Ulupalakua (Maui)

Completed exploration studies; the project has been awarded an exploration grant of $4.9 million under the DOE’s Innovative Exploration and Drilling Projects program.

Kula	Lease acquired but no further action has yet been taken

Kona	Under exploration studies.

Oregon [4]

Glass Buttes — Mahogany

Completed exploration studies. The project has been awarded an exploration grant of $4.3 million under the DOE’s Innovative Exploration and Drilling Projects program.

Glass Buttes — Midnight Point

Completed exploration studies; awaiting permits to start exploratory drilling.

Newberry — Twilight

Started exploratory drilling.

Lakeview/ Goose Lake

Completed exploration studies.

Idaho [1]

Magic Reservoir

Lease acquired but no further action has yet been taken.

Alaska [1]

Mount Spurr

Performed exploration drilling at the site; a $2.0 million exploration grant has been awarded from the Alaska Electricity Authority.

Utah [2]

Drum Mountain

Under exploration studies.

Whirlwind Valley

Under exploration studies.

New Mexico [1]

Rincon

Lease acquired but no further action has yet been taken.

Guatemala [2]

Amatitlan Phase II

Completed exploration studies; expected to start exploratory drilling.

Tecumburu

Under exploration studies.

New Zealand [1]

Tikitere

Signed BOT agreement; no further action has yet been taken.

In addition, we have exploration concessions for geothermal resources of approximately 336,000 acres in the following prospects:

Chile [6]

San Pablo

Exploration concession has been approved; started exploration studies.

Aroma

Exploration concession has been approved; started exploration studies.

Mariman

Exploration concession has been approved; started exploration studies.

Quinohuen

Exploration concession has been approved; started exploration studies.

San Jose II

Exploration concession has been approved; started exploration studies.

Sollipulli

Exploration concession has been approved; started exploration studies.

We also have an option to enter into geothermal leases covering more than 264,000 acres under a lease option agreement with Weyerhaeuser Company and agreement to conduct exploration activity at Warm Springs Tribe. We are currently exploring the following prospects:

Oregon [5]

Foley Hot Springs

Started exploration studies.

Silver Lake

Started exploration studies.

Summer Lake

Started exploration studies.

Winema

Started exploration studies.

Warm Springs Tribe

Started exploration studies.

Others

Solar PV Projects (Israel)

We have rights to develop ground-mounted and roof-top Solar PV projects in Israel, either by ourselves or with a third party. Due to the changes in the feed-in tariff under the current regulation in Israel, resulting in significantly lower than initially expected feed-in tariff, together with a long permitting process, we currently decided to exclude those projects from our plan for future development.

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 consideration for the power units is usually paid 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.

•

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 a capacity ranging between 200 watts and 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 for various other uses, including heavy duty direct current generators. The terms of sale of the turbo-generators are similar to those for the power units produced 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 the same customers described above that we target for the sale of our power units for recovered energy-based power generation. Unlike many other companies that provide EPC services, we have an advantage in that we are using our own manufactured equipment and thus have better control over the timing and delivery of required equipment and its 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 and remote power units and other generators, we enter, from time to time, into sales agreements 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 $262.2 million as of February 15, 2013, which includes revenues for the period between January 1, 2013 and February 15, 2013, compared to $241.0 million as of February 15, 2012, which included revenues for the period between January 1, 2012 and February 15, 2012. The approximately $262.2 million in product backlog as of February 15, 2013 includes an EPC contract in the amount of $21.0 million related to the Thermo 1 project with Cyrq, for which revenue will be recognized when payment by the customer is reasonably assured.

The following is a breakdown of the Product Segment backlog as of February 15, 2013 (in millions):


	Expected Completion of the Contract		Sales Expected to be Recognized in 2013		Sales Expected to be Recognized in the years following 2013		Expected Until End of Contract
Geothermal		2014	$	161-171	$	66-76	$	237
Recovered Energy		2013		13		—		13
Remote Power Units		2013		4		—		4
Other		2014		2		5		8

Total			$	180-190	$	72-82	$	262

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.

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 United States are CalEnergy, Calpine, Terra-Gen Power LLC, Enel Green Power and other smaller-sized pure play developers. Outside the United States, our competitors in the geothermal sector include companies such as Chevron Corporation, Energy Development Corporation in the Philippines, developers such as Star Energy and Medco Energi in Indonesia, Mighty River Power and Contact Energy in New Zealand and Enel Green Power, Alterra Power, Geo Global Energy and others in Chile. While the geothermal industry is characterized by high barriers to entry, national electric utilities or state-owned oil companies might also enter the market.

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.

Product Segment

Our competitors among power plant equipment suppliers are divided into: high enthalpy and low enthalpy competitors. The main high enthalpy competitors are industrial turbine manufacturers such as Mitsubishi, Fuji and Toshiba of Japan, GE/Nuovo Pignone and Ansaldo Energia of Italy, and Alstom S.A. of France.

The low enthalpy competitors are either binary systems manufacturers using the Organic Rankine Cycle such as Fuji of Japan, Atlas Copco Company, GE-Nuovo Pignone of Italy, and Turboden, or systems integrators such as Turbine Air Systems and Geothermal Development Associates (GDA) of the U.S. 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 in excess of 90%), an increase in competition, which we currently expect, may impact our ability to secure new purchase orders from potential customers. The increased competition may also lead to a reduction in the prices that we are able to charge for our binary equipment, which in turn may impact our profitability.

In the REG business, our competitors are other Organic Rankine Cycle manufacturers (such as GE and Turboden), manufactures that use Kalina technology (such as Wasabi Energy of Australia), 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.

When the proposed project is an EPC project we also compete with other service suppliers, such as project/engineering companies.

Customers

Most of our revenues from the sale of electricity in the year ended December 31, 2012 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, and SCPPA accounted for 17.5%, 15.3%, 9.4% and 1.5% of revenues, respectively, for the year ended December 31, 2012. Based on publicly available information, as of December 31, 2012, the issuer ratings of Southern California Edison, HELCO, Sierra Pacific Power Company, Nevada Power Company, and SCPPA were as set forth below:


Issuer	Standard & Poor’s Ratings Services	Moody’s Investors Service Inc.
Southern California Edison	BBB+ (stable outlook)	A3 (stable outlook)
HELCO	BBB- (stable outlook)	Baa1
Sierra Pacific Power Company	BB+ (stable outlook)	Ba1 (stable outlook)
Nevada Power Company	BB+ (stable outlook)	Ba1 (stable outlook)
SCPPA	BBB (outlook developing)	Aa3 (stable outlook)

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. In 2012, the revenues derived from a contract signed with Mighty River Power were more than 10% of our Product Segment revenues.

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 such raw materials are readily available from various suppliers.

We use subcontractors for some of the manufacturing for 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, 2012, we employed 1,252 employees, of which 543 were located in the United States, 538 were located in Israel and 171 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.

None of our employees (other than the employees at the Momotombo power plant) are represented by a labor union, and 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 United States, we currently do not have employees represented by unions under collective bargaining agreements. However, a union has recently filed a petition with the National Labor Relations Board (NLRB) in an attempt to organize our employees in our Puna complex in Hawaii. The matter is being processed and adjudicated under NLRB procedures.

We have no collective bargaining agreements with respect to our Israeli employees. However, by order of the Israeli Ministry of Industry, Trade and Labor, 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 non-managerial, finance and administrative, and sales and marketing personnel. This collective bargaining agreement principally concerns cost of living 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 and earthquake coverage, and primary and excess liability insurance, as well as customary worker’s compensation and automobile insurance and such other 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.

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 the Overseas Private Investment Corporation (an agency of the U.S. government), or MIGA (a member of the World Bank Group), and 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. We have obtained such insurance for all of our foreign power plants currently in operation. However, the policy for the Amatitlan Geothermal Project in Guatemala was terminated following the financing of the project in 2009 due to

our reduced equity exposure. Such insurance policies generally cover, subject to the limitations and restrictions contained therein, approximately 90% of our 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.

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 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 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 the 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 this final rule 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. However, the rule protects a Qualifying Facility’s rights under any contract or obligation for the sale of energy in effect or pending approval before the appropriate state regulatory authority or non-regulated electric utility on August 8, 2005. Until that contract expires, is terminated or is materially modified, the Qualifying Facility will not be required to file 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.

We expect that our power plants in the United States 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, the power plants’ existing PPAs will not be affected, but the utilities will not be obligated under PURPA to renew these PPAs or execute new PPAs upon the existing PPAs’ expiration.

PUHCA

PUHCA was repealed, effective February 8, 2006, pursuant to the Energy Policy Act of 2005. Although PUHCA was repealed, the Energy Policy Act of 2005 created the new PUHCA 2005. 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 that make only wholesale sales of electricity are not subject to state commissions’ rate, financial, and organizational 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, among other authorities, the FERC has exclusive rate-making jurisdiction over 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 United States 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, the 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, the 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 received 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. 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.

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. 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. 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 hazardous materials storage and management permits and pressure vessel operating permits. We are also required to obtain water rights permits in Nevada and may be required to obtain groundwater permits in California to use groundwater resources for makeup water. 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 or other penalties.

Environmental Laws and Regulations

Our facilities are subject to a number of environmental laws and regulations relating to development, construction and operation of geothermal facilities. In the United States, 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, 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 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 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 and should not be considered a full statement of the laws in such countries or all of the issues pertaining thereto.

Nicaragua. In 1998, two laws were approved by Nicaraguan authorities, Law No. 272-98 and Law No. 271-98, which define the structure of the energy sector in the country. Law No. 272-98 provides for the establishment of the CNE, which is responsible for setting policies, strategies and objectives as well as approving indicative plans for the energy sector. Law No. 271-98 formally assigned regulatory, supervisory, inspection and oversight functions to the INE.

In 2002, the National Congress enacted Law No. 443 to regulate the granting of exploration and exploitation concessions for geothermal fields. The INE adopted this law.

In 2007, Nicaragua passed Law No. 612 amending Law No. 290, which governs the organization of the executive branch. Among other matters, the new law established a new ministry of energy and mining, which has assumed all of the functions and responsibilities of the CNE. The new Ministry of Energy and Mining is responsible for administrating Law No. 443 described above, and is also responsible for granting concessions and permits relating to the exploration or exploitation of any energy source, as well as concessions and licensing for generation, transmission, and distribution of energy.

The Nicaraguan energy sector has been restructured and partially privatized. Following such restructuring and privatization, the government retained title and control of the transmission assets and created the ENATREL, which is in charge of the operation of the transmission system in the country and of the new wholesale market. As part of the restructuring, most of the distribution facilities previously owned by the Nicaraguan Electricity Company, the government-owned vertically-integrated monopoly, were transferred to two companies, DISNORTE and DISSUR, which in turn were privatized and acquired by an affiliate of Union Fenosa, a large Spanish utility. Following such privatization, the PPA for our Momotombo power plant was assigned by the Nicaraguan Electricity Company to DISNORTE and DISSUR. In addition, a National Dispatch Center was created to work with ENATREL and provide for dispatch and wholesale market administration.

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.

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). How this apparent overlap in functions will work out may only be known when county governments become operational after the forthcoming general elections.

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 63.7% of our total revenues for the year ended December 31, 2012 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:

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regular and unexpected maintenance and replacement expenditures;

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

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labor disputes;

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the presence of hazardous materials on our power plant sites;

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continued availability of cooling water supply;

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catastrophic events such as fires, explosions, earthquakes, landslides, floods, releases of hazardous materials, severe 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

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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. For example, in 2013 we plan to optimize the operation of our Mammoth complex and replace turbines, which were not manufactured by us. Such major maintenance activities impact both the capacity factor of the affected power plant and its operating costs.

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 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. 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. 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.

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. Serious seismic disturbances are possible and could result in damage to our power plants 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, 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.

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.

Unfavorable meteorological conditions may have a negative effect on electricity production at our Solar PV projects and, therefore, the revenue from such projects may be substantially below our expectations.

The electricity that we expect to produce and the revenue that we expect to generate by our Solar PV power plants are highly dependent on suitable solar conditions and associated weather conditions, which are beyond our control. It is possible that the solar energy at our Solar PV plants will be lower than expected, which would result in an unexpected reduction in energy production and performance and decreased revenues at our Solar PV 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. We recently entered the solar energy sector of the renewable energy industry and have signed a PPA with the IID for a 10 MW Solar PV project to be built in Imperial Valley, California. Our success in developing a particular project is contingent upon, among other things, negotiation of satisfactory engineering and construction agreements and PPAs, receipt of required governmental permits, obtaining adequate financing, and the timely implementation and satisfactory completion of construction. 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, 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. Our lack of experience in the Solar PV sector may also affect our ability to successfully develop, construct, finance, and operate the Solar PV power projects.

Currently, we have power plants under exploration, development or construction in the United States, Kenya, Chile, Guatemala, New Zealand, Honduras and Indonesia, 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:

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unanticipated cost increases;

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shortages and inconsistent qualities of equipment, material and labor;

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work stoppages;

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inability to obtain permits and other regulatory matters;

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failure by key contractors and vendors to timely and properly perform, including in the Solar PV sector where we will use equipment manufactured by others;

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inability to secure the required transmission capacity;

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

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our attention to other projects, including those in the solar energy sector.

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.

The aftermath of the recent global recession and its attendant credit constraints could adversely affect us.

We may continue to experience lower levels of worldwide demand for energy and face tighter credit markets, as the world economy continues to recover from the disruption in the global credit markets, failures or material business deterioration of investment banks, commercial banks, and other financial institutions, concerns over the European Union debt and currency crisis and significant reductions in asset values across businesses, households and individuals that led to the recent global recession. These conditions may adversely affect both our Electricity and Product Segments. Among other things, we might face:

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potential adverse impacts on our ability to negotiate waivers or modifications of the terms of existing financing arrangements with existing lenders if and when that might be necessary;

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potential declines in revenues in our Product Segment due to reduced or postponed orders or other factors caused by economic challenges faced by our customers and prospective customers; and

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potential adverse impacts on our customers’ ability to pay, when due, amounts payable to us and related increases in our cost of capital associated with any increased working capital or borrowing needs we may have if this occurs, or to collect amounts payable to us in full (or at all) if any of our customers fail or seek protection under applicable bankruptcy or insolvency laws.

Any of these things could materially adversely affect our business, financial condition, operating results, and cash flow.

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. As of December 31, 2012, we had approximately $1,030.9 million of total consolidated indebtedness, of which approximately $595.4 million represented non-recourse and limited recourse debt held by our subsidiaries. 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 (including those described in the immediately preceding risk factor) 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 (as discussed above), 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, parent company loans or the incurrence of additional debt by us.

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 prospects.

Our foreign power plants 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 delay or reduce our ability to profit from such power plants.

We have substantial operations outside of the United States that generated revenues in the amount of $247.0 million for the year ended December 31, 2012, which represented 48.0% of our total revenues for such year. 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 power plants in the United States, 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. Our foreign operations are also subject to significant political, economic and financial risks, which vary by country, and include:

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changes in government policies or personnel;

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changes in general economic conditions;

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restrictions on currency transfer or convertibility;

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changes in labor relations;

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political instability and civil unrest;

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changes in the local electricity market;

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

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expropriation and confiscation of assets and facilities.

In particular, 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 Nicaragua, subsidiaries of Union Fenosa, which are the off-takers of our Momotombo power plant, have been experiencing difficulties adjusting the tariffs charged to their customers, thus affecting their ability to pay for electricity they purchase from power generators. This may adversely affect our Momotombo power plant. In addition, recent sentiment in Kenya suggests increased opposition to the presence of foreign investors generally, including in the electricity sector. In addition, further re-organization of KPLC has been made with the formation of a new company known as KETRACO to undertake power transmission. No announcement has been made as to whether KPLC’s transmission assets will be transferred to KETRACO. In addition, the state owned GDC has begun operations, and has been charged with geothermal assessment, drilling of steam wells and sale of steam to future IPPs and to KenGen for electricity generation. 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.

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 net revenue 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 net revenue is attributed to revenues derived from power purchasers under the relevant PPAs. Southern California Edison, Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy), HELCO, and KPLC have accounted for 17.5%, 15.3%, 9.4%, and 7.9%, respectively, of our revenues for the year ended December 31, 2012. 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.

Seasonal variations may cause significant 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 in states that have renewable portfolio standards, the failure to supply the contracted capacity and energy thereunder may result in the imposition of penalties.

Under the PPAs of our Burdette (Galena 1), Desert Peak 2, Galena 2, Galena 3, Jersey Valley, McGinness Hills, Tuscarora and North Brawley power plants, we may be required to make payments to the relevant power purchaser in an amount equal to such purchaser’s replacement costs for renewable energy relating to any shortfall amount of renewable energy that we do not provide as required under the PPA and which such power purchaser is forced to obtain from an alternate source. All of these plants were in commercial operation in 2012, and to date, except in the case of North Brawley power plant, the shortfall amount has not been material. In the case of North Brawley, which operates below its contract capacity level, the purchaser’s replacement costs are materially lower than the PPA’s energy rate and therefore no payment is required. In addition, we may be required to make payments to the relevant power purchaser in an amount equal to its replacement costs relating to any renewable energy credits we do not provide as required under the relevant PPA. We may be subject to certain penalties, and we may also be required to pay liquidated damages if certain minimum performance requirements are not met under certain of our PPAs. With respect to the Brady PPA, we may also be required to pay liquidated damages of approximately $1.5 million (increased by the percent change in GNP deflator) to our power purchaser if the relevant power plant does not maintain availability of at least 85% during applicable peak periods. Any or all of these 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 electrical energy itself or purchased such energy 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 and in the future, it will be based on Southern California Edison’s SRAC, as

determined by the CPUC. These 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.

In December 2010, a global settlement (Global Settlement) relating primarily to the purchase and payment obligations of investor-owned utilities to Qualifying Facilities was approved by the CPUC and became effective on November 23, 2011. Under the terms of the Global Settlement, existing Qualifying Facilities with “Legacy PPAs” (meaning any PPA that was in effect at the time the Global Settlement went into effect) had the option to choose to enter into a “Legacy PPA Amendment” within 180 days of the effectiveness of the Global Settlement. The Legacy PPA Amendment allowed a Qualifying Facility to choose a pricing methodology option going forward from the “pricing effective date”, which in our case was the end of the fixed rate period that terminated April 2012 under a prior settlement agreement with Southern California Edison until December 31, 2014, after which the SRAC will be tied only to a formula with energy market heat rates. The pricing options that we chose for our PPAs:

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In the case of our Ormesa complex and Heber complex PPAs we switched to a new SRAC methodology, which includes fixed rates, declining heat rates, a variable O&M component, an adjustment based on location, and a price adjustment if GHG costs are imposed on the facility, all until December 31, 2014, after which the SRAC will be tied only to a formula with energy market heat rates; and

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In the case of our Mammoth complex PPAs we switched to the same formula specified in (1) above but with somewhat higher heat rates, no GHG cost adder and no location adjustment (for renewable resources).

The Global Settlement further provides that after July 1, 2015 if the term of a Qualifying Facility’s Legacy PPA expires, the investor-owned utilities would have no obligation to purchase power from the Qualifying Facility if the Qualifying Facility has a generating capacity in excess of 20 MW. Qualifying Facilities below 20 MW 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. Our existing PPAs with California investor-owned utilities are not affected by this waiver.

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 the 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 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 some or all of our domestic power plants refund 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 received from our domestic power plants, either of which would have an adverse effect on our revenues. Even if a power plant does not lose its Qualifying Facility status, pursuant to a final rule 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. Existing PPAs between a Qualifying Facility and a utility are not affected. If, in addition to California, 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.

Our financial performance is significantly dependent on the successful operation of our power plants, which is subject to 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. Our power purchasers or we 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 isobutane, isopentane, 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 United States, 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.

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 not be able to successfully integrate companies which we 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:

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

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inability to retain key personnel of the acquired companies;

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risks associated with unanticipated events or liabilities; and

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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.

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, recovered energy-based power plants, and Solar PV power plants have 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, cash grants, loan guaranties, 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.

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 and Solar PV power plants. 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, recovered energy-based, and Solar PV 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, and Solar PV 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.

We face competition from other companies engaged in the solar energy 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 lack of experience in the Solar PV sector may affect our ability to successfully develop, construct, finance, and operate Solar PV power projects.

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 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. Our revenues for the year ended December 31, 2012, from the power plants utilizing the IID transmission system, were approximately $77.2 million. The impact of such force majeure would depend on the duration thereof, with longer outages resulting in greater revenue loss. 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.

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 or construct and operate Solar PV facilities which require large areas of relatively flat land.

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, thereby affecting our ability to utilize, access, inject, and/or transport geothermal resources on or underneath the affected surface areas. 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 and any future expansion of our Solar PV plant near the Heber complex.

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.

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.

Our success is largely dependent on the skills, experience and efforts of our senior management team and other key personnel. In particular, our success depends on the continued efforts of Lucien Bronicki, Yehudit Bronicki and Yoram Bronicki, and other key employees. The loss of the services of any key employee could materially harm our business, financial condition, future results and cash flow. Although to date we have been successful in retaining the services of senior management and have entered into employment agreements with Lucien Bronicki, Yehudit Bronicki and Yoram Bronicki, such members of our senior management may terminate their employment agreements without cause and with notice periods ranging from 30 to 180 days. In addition, while Lucien and Yehudit Bronicki have not indicated any plan to retire, they are 78 and 71 years old, respectively, and either of them may decide to retire at any time. We may also not be able to locate or employ on acceptable terms qualified replacements for our senior management or key employees if their services were no longer available.

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.

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, such failure may materially and adversely affect our business, financial condition, future results, and cash flow.

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

Our intellectual property rights 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 and systems and physical assets, 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.

Possible fluctuations in the cost of construction, raw materials, 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, and on the supply of various industrial equipment components that we use. We currently obtain all such materials 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 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 all of our 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 all of our production and manufacturing facilities are located in Israel. Operations in Israel accounted for approximately 18.0%, 22.9% and 18.8% of our operating expenses in the years ended December 31, 2012, 2011 and 2010, respectively. 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 and November 2012, 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 recent political instability and civil unrest in the Middle East and North Africa (including the ongoing civil war in Syria) as well as the recently 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.

If our parent defaults on its lease agreement with the Israel Land Administration, or is involved in a bankruptcy or similar proceeding, our rights and remedies under certain agreements pursuant to which we acquired our product business and pursuant to which we sublease our land and manufacturing facilities from our parent may be adversely affected.

We acquired our business relating to the manufacture and sale of products for electricity generation and related services from our parent, Ormat Industries. In connection with that acquisition, we entered into a sublease with Ormat Industries for the lease of the land and facilities in Yavne, Israel where our manufacturing and production operations are conducted and where our Israeli offices are located. Under the terms of our parent’s lease agreement with the Israel Land Administration our sublease is for a period of twenty-five years less one day. The consent of the Israel Land Administration was obtained for a period of the shorter of (i) 25 years or (ii) the remaining period of the underlying lease agreement with the Israel Land Administration, which terminates between 2018 and 2047. We recently entered into a new lease agreement with Ormat Industries for the sublease of additional manufacturing facilities that were built adjacent to the existing facilities. The agreement will expire on the same date as the abovementioned agreement. If our parent were to breach its obligations to the Israel Land Administration under its lease agreement, the Israel Land Administration could terminate the lease agreement and, consequently, our sublease would terminate as well.

As part of the acquisition described in the preceding paragraph, we also entered into a patent license agreement with Ormat Industries, pursuant to which we were granted an exclusive license for certain patents and trademarks relating to certain technologies that are used in our business. If a bankruptcy case were commenced by or against our parent, it is possible that performance of all or part of the agreements entered into in connection with such acquisition (including the lease of land and facilities described above) could be stayed by the bankruptcy court in Israel or rejected by a liquidator appointed pursuant to the Bankruptcy Ordinance in Israel and thus not be enforceable. Any of these events could have a material and adverse effect on 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 United States 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.

Those of our directors and executive officers who also hold positions with our parent may have conflicts of interest with respect to matters involving both companies.

Two of our eight directors are directors and/or officers of Ormat Industries, namely Yehudit Bronicki and Gillon Beck. Our Chief Technology Officer, Lucien Bronicki is a director of Ormat Industries. In addition, two of our executive officers are also executive officers of Ormat Industries, namely our Chief Financial Officer,

Joseph Tenne, is the Chief Financial Officer of our parent, and our Senior Vice President — Contract Management and Corporate Secretary, Etty Rosner, is the Corporate Secretary of our parent. These directors and officers owe fiduciary duties to both companies and may have conflicts of interest on matters affecting both us and our parent, and in some circumstances may have interests adverse to our interests.

Our parent or its controlling stockholders may take actions that conflict with your interests.

Ormat Industries holds approximately 60% of our common stock. Because of these holdings, our parent company will be able to exercise control over all matters requiring stockholder approval, including the election of our directors, amendment of our certificate of incorporation and approval of our significant corporate transactions, and they will have significant control over our management and policies. The directors elected by our parent will be able to significantly influence decisions affecting our capital structure, dividend policies, share issuances and repurchases, and other matters presented for action by our directors. This control may have the effect of delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in their best interest.

Certain of our parent company’s shareholders, through their ownership of our parent’s shares, by contract or otherwise, may also affect our management and policies in various respects. As of February 28, 2013 approximately:

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22.07% of our parent’s ordinary shares was held by Bronicki Investments, a privately held Israeli company that is controlled by Lucien and Yehudit Bronicki.

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22.50% of our parent’s ordinary shares was held by FIMI.

Bronicki Investments and FIMI are parties to a Shareholders Rights Agreement (the “Shareholder Agreement”) that, among other things, includes joint voting and other arrangements that affect our parent and in certain cases its subsidiaries, including us and our subsidiaries. The principal impact of that Shareholder Agreement on us and our subsidiaries are undertakings that:

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subject to any applicable law and fiduciary duties, Bronicki Investments and FIMI will use their reasonable efforts to cause an equal number of designees of Bronicki Investments and FIMI to be elected or appointed to our Board of Directors and to the boards of all active subsidiaries of our parent (including our subsidiaries). In the case of our board, FIMI and Bronicki Investments each have the right to designate four members (subject to staged adjustments if either FIMI or Bronicki Investments or both cease to own specified minimum amounts of our parent’s ordinary shares, within various ranges specified in the Shareholder Agreement); and

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subject to any applicable law, use their best efforts to cause (subject to continued holding of certain minimum amounts of our parent’s ordinary shares):

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the continued service of Yehudit Bronicki as our Chief Executive Officer and of Yoram Bronicki as our President and Chief Operations Officer, in each case for a service period set forth in the Shareholder Agreement. If either Yehudit Bronicki or Yoram Bronicki is unable to fulfill these positions, Bronicki Investments is entitled to appoint to the applicable position another designee;

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the appointment of FIMI’s designee to serve as our Chairman of the Board for a service period set forth in the Shareholder Agreement; and

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after the expiration of the service periods referred to above, the nomination of Bronicki Investments’ designee as our Chief Executive Officer or Chairman of the Board (as Bronicki Investments may decide in its sole discretion), and the appointment of FIMI’s designee as our Chairman of the Board (if Bronicki Investments’ designee serves as Chief Executive Officer) or our Chief Executive Officer (if Bronicki Investments’s designee serves as Chairman of the Board).

The persons currently serving as our directors, Chairman of the Board, Chief Executive Officer and President and Chief Operations Officer are as contemplated by the Shareholders Agreement.

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:

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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;

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

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

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announcements of significant contracts by us or our competitors;

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

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restatements of historical financial results and changes in financial forecasts;

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loss of one or more of our significant customers;

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legislation;

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changes in market valuation or earnings of our competitors;

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the trading volume of our common stock; and

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general economic conditions.

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, our parent, Ormat Industries holds approximately 60% 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. On November 10, 2004, we entered into a registration rights agreement with Ormat Industries whereby Ormat Industries may require us to register our common stock held by it or its directors, officers and employees with the SEC or to include our common stock held by it or its directors, officers and employees in an offering and sale by us.

Provisions in our charter documents and Delaware law may delay or prevent 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 do not permit actions by our stockholders by written consent. In addition, 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 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. Our Board of Directors has the right to issue preferred stock without stockholder approval, which could be used to institute a “poison pill” that would work to dilute the stock ownership of a potential hostile

acquirer, effectively preventing acquisitions that have not been approved by our Board of Directors. 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. Although we believe these provisions provide for an opportunity to receive a higher bid by requiring potential acquirers to negotiate with our Board of Directors, these provisions apply even if the offer may be considered beneficial by some stockholders.

New 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 new 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 in May 2014 disclosing, among others, whether such minerals originate from the Democratic Republic of Congo or adjoining countries. The implementation of these new requirements could adversely affect the sourcing, availability and pricing of minerals used in the manufacture of certain components incorporated in our products. In addition, to the extent the rules apply to us, we will 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.

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 feet office and manufacturing facility located in the Industrial Park of Yavne, Israel, which we sublease from Ormat Industries. 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 is a party during the fiscal year 2012, other than as described below.

Securities Class Actions

Following the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs, three securities class action lawsuits were filed in the United States District Court for the District of Nevada on March 9, 2010, March 18, 2010 and April 7, 2010. These complaints asserted claims against the Company and certain directors and officers for alleged violations of Sections 10(b) and 20(a) of the Exchange Act. One complaint also asserted claims for alleged violations of Sections 11, 12(a) (2) and 15 of the Securities Act. All three complaints alleged claims on behalf of a putative class of purchasers of the Company’s common stock between May 6, 2008 or May 7, 2008 and February 23, 2010 or February 24, 2010. These three lawsuits were consolidated by the Court in an order issued on June 3, 2010, and the Court appointed three of the Company’s stockholders to serve as lead plaintiffs.

Lead plaintiffs filed a consolidated amended class action complaint (CAC) on July 9, 2010 that asserted claims under Sections 10(b) and 20(a) of the Exchange Act on behalf of a putative class of purchasers of the Company’s common stock between May 7, 2008 and February 24, 2010. The CAC alleged that certain of the Company’s public statements were false and misleading for failing to account properly for the Company’s exploration and development costs based on the Company’s announcement on February 24, 2010 that it was going to restate certain of its financial results to change its method of accounting for exploration and development costs in certain respects. The CAC also alleged that certain of the Company’s statements concerning the North Brawley project were false and misleading. The CAC sought compensatory damages, expenses, and such further relief as the Court may deem proper.

Defendants filed a motion to dismiss the CAC on August 13, 2010. On March 3, 2011, the Court granted in part and denied in part defendants’ motion to dismiss. The Court dismissed plaintiffs’ allegations that the Company’s statements regarding the North Brawley project were false or misleading, but did not dismiss plaintiffs’ allegations regarding the 2008 restatement. Defendants answered the remaining allegations in the CAC regarding the restatement on April 8, 2011, and the case entered the discovery phase. On July 22, 2011, plaintiffs filed a motion to certify the case as a class action on behalf of a class of purchasers of the Company’s common stock between February 25, 2009 and February 24, 2010, and defendants filed an opposition to the motion for class certification on October 4, 2011.

Subsequently, the parties participated in mediation where they reached an agreement in principle to settle the securities class action lawsuits. The parties thereafter filed a stipulation of settlement with the U.S. District Court for the District of Nevada on March 27, 2012, providing that the claims against the Company and its directors and officers will be dismissed with prejudice and plaintiffs will release the defendants from all claims in exchange for a cash payment of $3.1 million to be funded by the Company’s insurers. The stipulation of settlement received preliminary approval by the Court on March 30, 2012, and final approval on October 16, 2012.

The Company and the individual defendants have steadfastly maintained that the claims raised in the securities class action lawsuits were without merit, and have vigorously contested those claims. As part of the settlement, the Company and the individual defendants continue to deny any liability or wrongdoing under the securities laws or otherwise.

Stockholder Derivative Cases

Four stockholder derivative lawsuits have also been filed in connection with the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs. Two cases were filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe on March 16, 2010 and April 21, 2010, and two cases were filed in the United States District Court for the District of Nevada on March 29, 2010 and June 7, 2010. All four lawsuits assert claims brought derivatively on behalf of the Company against certain of its directors and officers for alleged breach of fiduciary duty and other claims, including waste of corporate assets and unjust enrichment.

The two stockholder derivative cases filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe were consolidated by the Court in an order dated May 27, 2010, and the plaintiffs filed a consolidated derivative complaint on September 7, 2010. In accordance with a stipulation between the parties, defendants filed a motion to dismiss on November 16, 2010. On April 18, 2011, the Court stayed the state derivative case pending the resolution of the securities class action lawsuits.

The two stockholder derivative cases filed in the United States District Court for the District of Nevada were consolidated by the Court in an order dated August 31, 2010, and plaintiffs filed a consolidated derivative complaint on October 28, 2010. The Company filed a motion to dismiss on December 13, 2010. On March 7, 2011, the Court transferred the federal derivative case to the Court presiding over the securities class action, and on August 29, 2011, the Court stayed the federal derivative case pending the resolution of the securities class action lawsuits.

The parties to all the stockholder derivative cases executed a stipulation of settlement to resolve all cases on September 25, 2012. The stipulation provides that: (i) all claims asserted in the derivative cases will be dismissed with prejudice and that plaintiffs will release the defendants from all claims; (ii) the Company will implement and/or maintain certain corporate governance measures for no less than five years; and (iii) plaintiffs’ counsel will receive attorneys’ fees of $700,000 to be funded by the Company’s insurers. The stipulation of settlement received preliminary approval by the Second Judicial District Court of the State of Nevada in and for the County of Washoe on October 22, 2012 and final approval on December 17, 2012 thereby dismissing the stockholder derivative cases pending in that court. Shortly thereafter on December 27, 2012, the United States District Court for the District of Nevada dismissed the stockholder derivative cases pending before it.

The Company believes the allegations in these purported derivative actions were without merit and, as part of the settlement, continues to deny any liability or wrongdoing.

Others

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On December 24, 2012, Laborers’ International Union of North America Local Union No. 783 (LiUNA), an organized labor union, filed a petition in Mono County Superior Court, naming Mono County, California and the Company as defendant and real party in interest, respectively. The petitioners brought this action to challenge the November 13, 2012 decision of the Mono County Board of Supervisors in adopting Resolutions No. 12-78, denying Petitioners’ administrative appeal of the Planning Commission’s approval of Conditional Use Permit (CUP), adoption of findings under the California Environmental Quality Act (CEQA) and adoption of the final environmental impact report (EIR) for the Mammoth enhancement. The petition asks the court to set aside the approval of the CUP and adoption of the EIR and cause a new EIR to be prepared and circulated.

The Company believes that the petition is without merit and intends to respond and take necessary legal action to dismiss the proceedings. The Company responded to LiUNA’s petition. Filing of the petition in and of itself does not have any immediate adverse implications for the Mammoth enhancement.

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On January 4, 2012, the California Unions for Reliable Energy (CURE) filed a petition in Alameda Superior Court, naming the California Energy Commission (CEC) and the Company as defendant and real party in interest, respectively. The petition asks the court to order the CEC to vacate its decision which denied, with prejudice, the complaint filed by CURE against the Company with the CEC. The CURE complaint alleged that the Company’s North Brawley Project and East Brawley Project both exceed the CEC’s 50 MW jurisdictional threshold and therefore are subject to the CEC licensing authority rather than Imperial County licensing authority. In addition, the CURE petition asks the court to investigate and halt any ongoing violation of the Warren Alquist Act by the Company, and to award CURE attorney’s fees and costs. As to North Brawley, CURE alleges that the CEC decision violated the Warren Alquist Act because it failed to consider provisions of the County permit for North Brawley, which CURE contends authorizes the Company to build a generating facility with a number of OECs

capable of generating more than 50 MW. As to East Brawley, CURE alleges that the CEC decision violated the Warren Alquist Act because it failed to consider the conditional use permit application for East Brawley, which CURE contends shows that the Company requested authorization to build a facility with a number of OECs capable of generating more than 50 MW.

The Company believes that the petition is without merit and intends to respond and take necessary legal action to dismiss the proceedings. The parties have filed briefs in the proceeding, and the matter was set for hearing. The court held two hearings and on November 15, 2012 CURE’s petition was denied. Any appeal of the Court’s decision must be filed by Monday, March 4, 2013. The filing of the petition in and of itself does not have any immediate adverse implications for the North Brawley or East Brawley projects and the Company continues to operate the North Brawley project in the ordinary course of business and is proceeding with its development work on the East Brawley project.

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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.

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”. Public trading of our stock commenced on November 11, 2004. Prior to that, there was no public market for our stock. As of February 28, 2013, there were 16 record holders of the Company’s common stock. On February 28, 2013, our stock’s closing price as reported on the NYSE was $20.44 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 therefore. 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 11 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
February 22, 2011	$	0.05	March 15, 2011	March 24, 2011
May 4, 2011	$	0.04	May 18, 2011	May 25, 2011
August 3, 2011	$	0.04	August 16, 2011	August 25, 2011
May 8, 2012	$	0.04	May 21, 2012	May 30, 2012
August 1, 2012	$	0.04	August 14, 2012	August 23, 2012

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, 2011 and 2012, and from January 1, 2013 until February 28, 2013:


	First Quarter 2011		Second Quarter 2011		Third Quarter 2011		Fourth Quarter 2011		First Quarter 2012		Second Quarter 2012		Third Quarter 2012		Fourth Quarter 2012		January 1 to February 28, 2013
High	$	31.18	$	26.13	$	22.90	$	19.69	$	21.05	$	22.24	$	21.50	$	20.80	$	22.17
Low:	$	23.24	$	20.60	$	14.43	$	15.44	$	16.01	$	20.60	$	17.61	$	16.67	$	18.78

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, 2012 for our common stock, compared to the Standard and Poor’s Composite 500 Index, and two peer groups.

LOGO


	11/11/2004			12/31/2004			12/31/2005			12/31/2006			12/31/2007			12/31/2008			12/31/2009			12/31/2010			12/31/2011			12/31/2012
Ormat Technologies Inc		0.0			9	%		74	%		145	%		267	%		112	%		152	%		97	%		20	%		29	%
Standard & Poor’s Composite 500 Index		0	%		8	%		11	%		26	%		31	%		-20	%		-1	%		12	%		12	%		27	%
IPP Peers*		0	%		22	%		26	%		79	%		79	%		77	%		107	%		119	%		131	%		165	%
Renewable Peers*		0	%		41	%		19	%		63	%		204	%		20	%		45	%		-25	%		-22	%		-30	%

*	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”.

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, 2012, 2011 and 2010 and as of December 31, 2012 and 2011 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, 2009 and 2008 and as of December 31, 2010, 2009 and 2008 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,
	2012			2011			2010			2009			2008
	(In thousands, except per share data)
Statements of Operations Data:
Revenues:
Electricity	$	327,529		$	323,849		$	291,820		$	252,621		$	251,373
Product		186,879			113,160			81,410			159,389			92,577

Total revenues		514,408			437,009			373,230			412,010			343,950

Cost of revenues:
Electricity		244,634			244,037			242,326			179,101			169,297
Product		135,346			76,072			53,277			112,450			72,755

Total cost of revenues		379,980			320,109			295,603			291,551			242,052

Gross margin		134,428			116,900			77,627			120,459			101,898
Operating expenses:
Research and development expenses		6,108			8,801			10,120			10,502			4,595
Selling and marketing expenses		16,122			16,207			13,447			14,584			10,885
General and administrative expenses		28,267			27,885			27,442			26,412			25,938
Impairment charges		236,377			—			—			—			—
Write-off of unsuccessful exploration activities		2,639			—			3,050			2,367			9,828

Operating income (loss)		(155,085	)		64,007			23,568			66,594			50,652
Other income (expense):
Interest income		1,201			1,427			343			639			3,118
Interest expense, net		(64,069	)		(69,459	)		(40,473	)		(16,241	)		(14,945	)
Foreign currency translation and transaction gains (losses)		242			(1,350	)		1,557			(1,695	)		(4,421	)
Income attributable to sale of tax benefits		10,127			11,474			8,729			15,515			18,118
Gain on acquisition of controlling interest		—			—			36,928			—			—
Gain from extinguishment of liability		—			—			—			13,348			—
Other non-operating income (expense), net		590			671			130			200			(3,424	)

Income (loss) from continuing operations, before income taxes and equity in income (losses) of investees		(206,994	)		6,770			30,782			78,360			49,098
Income tax benefit (provision)		3,500			(48,535	)		1,098			(15,430	)		(5,310	)
Equity in income (losses) of investees, net		(2,522	)		(959	)		998			2,136			1,725

Income (loss) from continuing operations		(206,016	)		(42,724	)		32,878			65,066			45,513
Discontinued operations:
Income (loss) from discontinued operations, net of related tax		—			—			14			3,487			(2,221	)
Gain on sale of a subsidiary in New Zealand, net of related tax		—			—			4,336			—			—

Net income (loss)		(206,016	)		(42,724	)		37,228			68,553			43,292
Net loss (income) attributable to noncontrolling interest		(414	)		(332	)		90			298			316

Net income (loss) attributable to the Company’s stockholders	$	(206,430	)	$	(43,056	)	$	37,318		$	68,851		$	43,608


	Year Ended December 31,
	2012			2011			2010		2009		2008
	(In thousands, except per share data)
Earnings (loss) per share attributable to the Company’s stockholders:
Basic:
Income (loss) from continuing operations	$	(4.54	)	$	(0.95	)	$	0.72	$	1.44	$	1.04
Discontinued operations		—			—			0.10		0.08		(0.05	)

Net income (loss)	$	(4.54	)	$	(0.95	)	$	0.82	$	1.52	$	0.99

Diluted:
Income (loss) from continuing operations	$	(4.54	)	$	(0.95	)	$	0.72	$	1.43	$	1.03
Discontinued operations		—			—			0.10		0.08		(0.05	)

Net income (loss)	$	(4.54	)	$	(0.95	)	$	0.82	$	1.51	$	0.98

Weighted average number of shares used in computation of earnings (loss) per share attributable to the Company’s stockholders:
Basic		45,431			45,431			45,431		45,391		44,182

Diluted		45,431			45,431			45,452		45,533		44,298

Cash dividend per share declared during the year	$	0.08		$	0.13		$	0.27	$	0.25	$	0.20

Balance Sheet Data (at end of year):
Cash and cash equivalents	$	66,628			99,886			82,815		46,307		34,393
Working capital		64,704			98,415			66,932		55,652		3,296
Property, plant and equipment, net (including construction-in process)		1,622,899			1,889,083			1,696,101		1,517,288		1,334,859
Total assets		2,094,114			2,314,718			2,043,328		1,864,193		1,630,976
Long-term debt (including current portion)		1,030,928			1,025,010			789,669		624,442		386,635
Notes payable to Parent (including current portion)		—			—			—		9,600		26,200
Equity		702,198			906,644			945,227		911,695		847,235

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 engaged primarily in the geothermal and recovered energy power business. We design, develop, build, sell, own, and operate clean, environmentally friendly geothermal and recovered energy-based power plants, in most cases using equipment that we design and manufacture.

•

The Electricity Segment — in this segment, we develop, build, own and operate geothermal and recovered energy-based power plants in the United States and geothermal power plants in other countries

around the world, and sell the electricity they generate. We have expanded our activities in the Electricity Segment to include the ownership and operation of power plants that produce electricity generated by Solar PV systems that we do not manufacture; and

•

Both our Electricity Segment and Product Segment operations are conducted in the United States and throughout the world. Our current generating portfolio includes geothermal plants in the United States, Guatemala, Kenya, and Nicaragua, as well as REG plants in the United States.

For the year ended December 31, 2012, our total revenues increased by 17.7% (from $437.0 million to $514.4 million) over the previous year.

For the year ended December 31, 2012, Electricity Segment revenues were $327.5 million, compared to $323.8 million for the year ended December 31, 2011, an increase of 1.1%, while Product Segment revenues for the year ended December 31, 2012 were $186.9 million, compared to $113.2 million during the year ended December 31, 2011, an increase of 65.1%.

During the years ended December 31, 2012 and 2011, our consolidated power plants generated 4,134,789 MWh and 3,854,123 MWh, respectively.

For the year ended December 31, 2012, our Electricity Segment represented approximately 63.7% of our total revenues, while our Product Segment represented approximately 36.3% of our total revenues. For the year ended December 31, 2011, our Electricity Segment represented approximately 74.1% of our total revenues, while our Product Segment represented approximately 25.9% of our total revenues.

In the year ended December 31, 2012, approximately 61.8% of our Electricity Segment revenues were derived 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:

•

The energy rates under the PPAs in California for each of the Ormesa complex, the Mammoth complex, and the Heber 1 and Heber 2 power plants (the California SO#4 PPAs) change based primarily on fluctuations in natural gas prices.

•

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.

We have attempted to reduce our exposure to fluctuations in the price of natural gas and oil until December 31, 2013 by entering into derivatives contracts, as described under “Recent Developments” in Item 1 — Business”.

Electricity Segment revenues are also subject to seasonal variations and can be affected by higher-than-average ambient temperatures, as described below under “Seasonality”. In addition, the revenues we report in our financial statements may show more variation due to our increased use of derivatives in connection with our variable price PPAs and the accounting principles associated with our use of those derivatives.

Revenues attributable to our Product Segment are based on the sale of equipment and the provision of various services to our customers. These revenues may vary from period to period because of the timing of our receipt of purchase orders and the progress of our execution of each project.

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

Trends and Uncertainties

The geothermal industry in the United States has historically experienced significant growth followed by a consolidation of owners and operators of geothermal power plants. During the 1990s, growth and development in the geothermal industry occurred primarily in foreign markets and only minimal growth and development occurred in the United States. Since 2001, there has been increased demand for energy generated from geothermal resources in the United States as costs for electricity generated from geothermal resources have become more competitive relative to fossil fuel generation. This has partly been due to increasing natural gas and oil prices during much of this period and, equally important, to legislative and regulatory requirements and incentives, such as state renewable portfolio standards and federal tax credits. The ARRA further encourages the use of geothermal energy through PTCs or ITCs as well as cash grants (which are discussed in more detail in “Government Grants and Tax Benefits” below). In response, the geothermal industry in the United States has seen a wave of new entrants and, over the last several years, consolidation involving smaller developers. We see the increasing demand for energy generated from geothermal and other renewable resources in the United States and the further introduction of renewable portfolio standards as significant trends affecting our industry today and in the immediate future. Our operations and the trends that from time to time impact our operations are subject to market cycles.

Although other 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 affected by the following trends, factors and uncertainties:

•

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 and in the Solar PV sector.

•

Our primary focus continues to be our organic growth through exploration, development, construction of new projects and enhancements of existing power plants. We expect that this investment in organic growth will increase our total generating capacity, consolidated revenues and operating income attributable to our Electricity Segment from year to year. In addition, we routinely look at acquisition opportunities.

•

The continued awareness of climate change may result in significant changes in the business and regulatory environments, which may create business opportunities for us. In 2011, the first phase of the EPA “Tailoring Rule” took effect. The Tailoring Rule sets thresholds addressing the applicability of the permitting requirements under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs to certain major sources of GHG emissions. Federal legislation or additional federal regulations addressing climate change are possible. In addition, several states and regions are already addressing climate change. For example, California’s state climate change law, AB 32, which was signed into law in September 2006, regulates most sources of GHG emissions and aims to reduce GHG emissions to 1990 levels by 2020. On October 20, 2011 the CARB adopted cap-and-trade regulations to reduce California’s greenhouse gas emissions under AB 32. In addition to California, twenty-two other U.S. states have set GHG emissions targets or goals. Regional initiatives, such as the Western Climate Initiative (which

includes California and four Canadian provinces) and the Midwest GHG Reduction Accord (which includes six U.S. states and one Canadian province), are also being developed to reduce GHG emissions and develop trading systems for renewable energy credits. In the United States, approximately 40 states have adopted RPS, renewable portfolio goals, or similar laws requiring or encouraging electric utilities in such states to generate or buy a certain percentage of their electricity from renewable energy sources or recovered heat sources. On April 12, 2011, Governor Jerry Brown signed California Senate Bill X1-2 (SBX1-2) which increased California’s RPS to 33% by December 31, 2020 and instituted a tradable REC program. SBX1-2 is expected to foster a liquid tradable REC market and lead to more creative off-take arrangements. Although we cannot predict at this time whether the tradable REC program under SBX1-2 and its implementing regulations will have a significant impact on our operations or revenue, it may facilitate additional options when negotiating PPAs and selling electricity from our projects. The CPUC recently authorized the utilities to procure 1,299 MW through the RAM program, a procurement mechanism for renewable distributed generation projects greater than 3 MW and up to 20 MW, by holding four auctions over two years. We expect that the additional demand for renewable energy from utilities in California will outpace a possible reduction in general demand for energy (if any) due to the effect of economic conditions. We see increased demand in California after 2016 driven by the impact of the increase in California’s RPS. This may create opportunities for us to replace some of our existing SO#4 PPAs, expand existing power plants and develop new power plants.

•

Outside of the United States, we expect that a variety of 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 competition from the wind and solar power generation industry to continue. While we believe the expected demand for renewable energy will be large enough to accommodate increased competition, any such increase and the amount of renewable energy under contract may contribute to a reduction in electricity prices. Despite increased competition from the wind and solar power generation industry, we believe that baseload electricity, such as geothermal-based energy, will continue to be a leading source of renewable energy in areas with commercially viable geothermal resource. In the geothermal industry, we are experiencing a notable decrease in competition, specifically in the acquisition of geothermal leases. The reduced level of competition has contributed to a decrease in lease costs.

•

In the Product Segment, we expect increased competition from binary power plant equipment suppliers. 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 in excess of 90%), an increase in competition may impact our ability to secure new purchase orders from potential customers. The increased competition may also lead to a reduction in the prices that we are able to charge for our binary equipment, which in turn may impact our profitability.

•

North America is the largest and most developed natural gas market in the world. As recently as five years ago, the region was considered to be short on supply, with an expected need to import significant volumes of LNG from the international gas market to balance supply with expected demand. The rise of shale gas production over the last three years has significantly changed the natural gas market landscape in North America. The unexpected growth in supply at increasingly lower costs has come at a time when the U.S. economy has been facing constrained demand growth for natural gas. The current low natural gas price level has led some producers to shut-in wells and reduce output, which in turn may increase natural gas prices. Among other things, the natural gas supply growth has led to an increased interest in exporting natural gas from the U.S. in the form of LNG. Various natural gas companies and other project sponsors have recently applied and, in some cases, already received an export license to export LNG to countries with which the U.S. has a free trade agreement providing comity in trading natural gas (FTA-nations) and to other non-FTA nations. At the same time, environmentalists, regulators, natural gas companies and the public have been focusing more attention on the potential environmental impacts associated with natural

100

gas fracking, including possible chemical leakage, ground water contamination and other effects, which may slow development in some areas. The changing natural gas landscape, the resulting effect on natural gas pricing (in either direction) and the corresponding implications for electric utilities and other producers of electricity in terms of planning for and choosing a source of fuel, will all affect the pricing under our PPAs that have SRAC pricing or that are otherwise tied to natural gas prices. In addition, the current low natural gas price level is causing some producers to shut-in wells and reduce output, which in turn may increase natural gas prices.

•

Our 25 MW PPA for the Puna complex has a monthly variable energy rate based on the local utility’s avoided costs. A decrease in the price of oil 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 and under any other variable energy rate in PPAs that we may enter into in the future. As described under “Recent Developments” in Item 1 — “Business”, we have entered into swap and put contracts to reduce our exposure to fluctuations in the energy rate caused by fluctuations in oil prices through December 31, 2013. Our use of derivative instruments for this purpose has increased, and likely will continue to increase, volatility in revenues and certain other line items in our financial statements due to applicable accounting standards.

•

Our PPAs for the Ormesa complex, the Mammoth complex and the Heber 1 and 2 power plants were fixed until May 1, 2012. Thereafter, the energy price component under these PPAs changed from a fixed rate to a variable rate based on SRAC pricing. These PPAs may be impacted by fluctuations in natural gas prices. As described under “Recent Developments” in Item 1 — “Business”, we have entered into put and swap transactions in an attempt to reduce our exposure to fluctuations in natural gas prices through December 31, 2013. Our use of derivative instruments for this purpose has increased, and likely will continue to increase, volatility in revenues and certain other line items in our financial statements due to applicable accounting standards.

•

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, economic and financial risks, which vary by country. As of the date of this annual report, those risks include the partial privatization of the electricity sector in Guatemala, labor unrest in Nicaragua and the political uncertainty currently prevailing in some of the countries in which we operate. Although we maintain political risk insurance for most of our foreign power plants to mitigate these risks, insurance does not provide complete coverage with respect to all such risks.

•

The Energy Policy Act of 2005 authorizes FERC to terminate, upon the request of a utility, the obligation of electric utilities 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. The legislation does not affect existing PPAs. We do not expect this change in law to affect our U.S. power plants significantly, as all of our current PPAs are long-term. FERC recently 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.

101

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 61.8% of our Electricity revenues for the year ended December 31, 2012 were derived from PPAs with fixed price components, we have variable price PPAs in California and Hawaii. Our California SO#4 PPAs are subject to the impact of fluctuations in natural gas prices. The prices paid for electricity pursuant to the 25 MW PPA for the Puna complex in Hawaii are impacted by the price of oil. Accordingly, our revenues from those power plants may fluctuate. As discussed in “Recent Developments” in Item 1 — “Business” in the year ended December 31, 2012, we entered into swap contracts and put transactions in an attempt to reduce our exposure to fluctuations in the prices of natural gas and oil, under the California SO#4 PPAs and under the 25 MW PPA for the Puna complex, until December 31, 2013.

Our Electricity Segment revenues are also subject to seasonal variations, as more fully described in “Seasonality” below, and may also be affected by higher-than-average ambient temperature, which could cause a decrease in the generating capacity of our power plants, and by unplanned major maintenance activities related to our power plants.

Our PPAs generally provide for the payment of 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 and the status and timing of such orders. 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 often 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 2011 and 2012, we experienced a significant increase in our Product Segment customer orders, which has increased our Product Segment backlog. We expect that our Product Segment revenues will remain robust until the end of 2013 as a result of these new orders and increased backlog, which is described in Item 1 — “Business”.

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


	Revenues in Thousands						% of Revenues for Period Indicated
	Year Ended December 31,						Year Ended December 31,
	2012		2011		2010		2012			2011			2010
Revenues:
Electricity	$	327,529	$	323,849	$	291,820		63.7	%		74.1	%		78.2	%
Product		186,879		113,160		81,410		36.3			25.9			21.8

Total	$	514,408	$	437,009	$	373,230		100.0	%		100.0	%		100.0	%

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Geographical 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,
	2012		2011		2010		2012			2011			2010
Electricity Segment:
United States	$	246,070	$	249,740	$	220,107		75.1	%		77.1	%		75.4	%
Foreign		81,459		74,109		71,713		24.9			22.9			24.6

Total	$	327,529	$	323,849	$	291,820		100.0	%		100.0	%		100.0	%

Product Segment:
United States	$	21,374	$	—	$	10,177		11.4	%		0.0	%		12.5	%
Foreign		165,505		113,160		71,233		88.6			100.0			87.5

Total	$	186,879	$	113,160	$	81,410		100.0	%		100.0	%		100.0	%

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 in California for the Heber 1 and 2 power plants, 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 during such months. In the winter, our power plants produce more energy principally due to the higher ambient temperature, and as a result have a favorable impact to energy revenues. However, the higher payments payable by Southern California Edison in the summer months have a more significant impact on our revenues than that of the higher energy revenues generally generated in winter due to increased efficiency. As a result, our electricity revenues are generally higher in the summer than in the winter.

Breakdown of Cost of Revenues

Electricity Segment

The principal cost of revenues attributable to our operating power plants includes operation and maintenance expenses (such as depreciation and amortization) 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, and insurance. In our California power plants our principal cost of revenues also includes transmission charges, scheduling charges and purchases of make-up water for use in our cooling towers. 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 4.3% and 3.7% of Electricity Segment revenues for the years ended December 31, 2012 and December 31, 2011, 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

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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, Cash Equivalents, Marketable Securities and Short-Term Bank Deposit

Our cash, cash equivalents, marketable securities and a short-term bank deposit as of December 31, 2012 decreased to $69.6 million from $118.4 million as of December 31, 2011. This decrease is principally due to: (i) our use of $233.0 million to fund capital expenditures; (ii) repayment of $74.5 million of long-term debt; (iii) $14.9 million of cash paid to the Class B membership units of OPC (see “OPC Transaction” below); and (iv) net repayment of $140.4 million to borrowers under our revolving credit lines with commercial banks. This decrease was partially offset by: (i) $214.1 million of net proceeds from the disbursements of $85.0 million representing the full amount of Tranche I of the OPIC Loan and $135.0 million from Tranche II of the OPIC Loan, as described above under “Non-Recourse and Limited-Recourse Third-Party Debt”; (ii) $89.5 million derived from operating activities during the year ended December 31, 2012; and (iii) cash grants in the total amount of $119.2 million received from the U.S. Treasury under Section 1603 of the ARRA in the second and third quarters of 2012 relating to the enhancement of our Puna geothermal complex and to our Jersey Valley, Tuscarora and McGinness Hills geothermal power plants. Our corporate borrowing capacity under committed lines of credit with different commercial banks as of December 31, 2012 was $445.8 million, as described below in “Liquidity and Capital Resources”, of which we have utilized $260.9 million (including $183.8 million of letters of credit) as of December 31, 2012.

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.

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

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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 (such as legal fees) 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. During the years ended December 31, 2012, and 2010, we determined that the geothermal resource at five and one of our exploration projects, respectively, would not support commercial operations and as such, we abandoned those sites (we did not abandon any such sites in the year ended December 31, 2011). As a result of this determination, we expensed $2,639,000 and $3,050,000 of capitalized costs during the years ended December 31, 2012, and 2010, 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 $67,565,000 and $78,653,000 at December 31, 2012 and 2011, respectively. Of this amount, $33,985,000 and $36,832,000 relates to up-front bonus payments at December 31, 2012 and 2011, respectively.

•

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.

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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, except for the North Brawley and the OREG 4 power plants described below, 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.

The North Brawley geothermal power plant was tested for impairment as of December 31, 2012 due to the low output and higher than expected operating costs. We placed the plant in service under its PPA with Southern California Edison in 2010. However, we found that the North Brawley geothermal field was significantly more difficult to operate than our other fields and the power plant was unable to reach its design capacity of 50 MW and instead operated at capacities between 20 MW and 33 MW. This generation level was achieved only after significant additional capital expenditures and higher than anticipated operating costs.

In order to improve the economics of the plant, we approached Southern California Edison to discuss various contractual alternatives to the PPA and, in early 2012, we reached a written understanding to engage in discussions with third parties about purchasing the power at higher rates. However, in a letter dated January 14, 2013, Southern California Edison informed us that it is no longer interested in pursuing alternatives to the current PPA, thus retracting its permission to us to explore a replacement PPA with higher electricity prices.

As a result of Southern California Edison’s notification and the rates under the existing PPA, coupled with a further understanding of the cost and probability of success of additional well field work which has been accumulated in recent months, we have concluded that it will not be economical for us to continue to invest the substantial capital required to increase the generating capacity of the power plant. Accordingly, we have decided to operate the plant at the current capacity level of approximately 27 MW and refrain from making additional capital investment to expand the capacity.

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Based on these indicators, we tested the power plant for recoverability by estimating its future cash flows taking into consideration rates to be received under the PPA with Southern California Edison through the end of its term and expected market rates thereafter, possible penalties for underperformance during periods when the plant is expected to operate below the stated capacity in the PPA, projected capital expenditures and projected operating expenses over the life of the plant.

As a result, the North Brawley power plant was written down to its fair value of $32.0 million. The impairment loss of $229.1 million is presented in our consolidated statement of operations and comprehensive income (loss) under “Impairment Charges”. As to the assumptions used in estimating the fair value of the North Brawley power plant see Note 7 to our consolidated financial statements set forth in Item 8 of this annual report.

OREG 4, a REG power plant was also tested for impairment in the third quarter of 2012 due to continued low run time of the compressor station that serves as its heat source, which resulted in low power generation and revenue. Based on these indicators, we tested the plant for recoverability by estimating its future cash flows over the life of the plant. Based on these indicators, we tested the power plant for recoverability by estimating its future cash flows taking into consideration rates to be received under the PPA through the end of its term, projected capital expenditures and projected operating expenses over the life of the plant.

As a result, the OREG 4 power plant was written down to its fair value of $3.6 million. The impairment loss of $7.3 million is presented in our consolidated statement of operations and comprehensive income (loss) under “Impairment Charges”. As to the assumptions used in estimating the fair value of the OREG 4 power plant see Note 7 to our consolidated financial statements set forth in Item 8 of this annual report.

The Jersey Valley geothermal power plant, which is under development, was tested for impairment in the year ended December 31, 2012 due to the low output resulting from injection constraints. Based on these indicators, we tested the power plant for recoverability by estimating its future cash flows taking into consideration the various outcomes from different generating capacities, rates to be received under the PPA through the end of its term and expected market rates thereafter, possible penalties for underperformance during periods when the plant is expected to operate below the stated capacity in the PPA, projected capital expenditures to complete development of the plant and projected operating expenses over the life of the plant. We applied a probability-weighted approach and considered alternative courses of action.

Using a probability-weighted approach, the estimated undiscounted cash flows exceed the carrying value of the plant ($65.5 million as of December 31, 2012) by approximately $31.2 million and therefore, we did not recognize an impairment charge. Estimated undiscounted cash flows are subject to significant uncertainties. If actual cash flows differ from our current estimates due to factors that include, among others, if the plant’s future generating capacity is less than approximately 10 MW, or if the capital expenditures required to complete development of the plant and/or future operating costs exceed the level of our current projections, a material impairment write-down may be required in the future.

•

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

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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.

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. becomes apparent, 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, we record the largest amount of tax benefit with a greater than 50% likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. 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 our recent construction of new power plants and enhancement of acquired power plants and fluctuation in revenues from our Product Segment.


	Year Ended December 31,
	2012			2011			2010
	(In thousands, except per share data)
Statements of Operations Historical Data:
Revenues:
Electricity	$	327,529		$	323,849		$	291,820
Product		186,879			113,160			81,410

		514,408			437,009			373,230

Cost of revenues:
Electricity		244,634			244,037			242,326
Product		135,346			76,072			53,277

		379,980			320,109			295,603

Gross margin:
Electricity		82,895			79,812			49,494
Product		51,533			37,088			28,133

		134,428			116,900			77,627
Operating expenses:
Research and development expenses		6,108			8,801			10,120
Selling and marketing expenses		16,122			16,207			13,447
General and administrative expenses		28,267			27,885			27,442
Impairment charges		236,377			—			—
Write-off of unsuccessful exploration activities		2,639			—			3,050

Operating income (loss)		(155,085	)		64,007			23,568
Other income (expense):
Interest income		1,201			1,427			343
Interest expense, net		(64,069	)		(69,459	)		(40,473	)
Foreign currency translation and transaction gains (losses)		242			(1,350	)		1,557
Income attributable to sale of tax benefits		10,127			11,474			8,729
Gain on acquisition of controlling interest		—			—			36,928
Other non-operating income, net		590			671			130

Income (loss) from continuing operations, before income taxes and equity in income of investees		(206,994	)		6,770			30,782
Income tax benefit (provision)		3,500			(48,535	)		1,098
Equity in income (losses) of investees, net		(2,522	)		(959	)		998

Income (loss) from continuing operations		(206,016	)		(42,724	)		32,878
Discontinued operations:
Income from discontinued operations, net of related tax		—			—			14
Gain on sale of a subsidiary in New Zealand, net of related tax		—			—			4,336

Net income (loss)		(206,016	)		(42,724	)		37,228
Net loss (income) attributable to noncontrolling interest		(414	)		(332	)		90

Net income (loss) attributable to the Company’s stockholders	$	(206,430	)	$	(43,056	)	$	37,318

Earnings (loss) per share attributable to the Company’s stockholders:
Basic:
Income (loss) from continuing operations	$	(4.54	)	$	(0.95	)	$	0.72
Discontinued operations		—			—			0.10

Net Income (loss)	$	(4.54	)	$	(0.95	)	$	0.82

Diluted:
Income (loss) from continuing operations	$	(4.54	)	$	(0.95	)	$	0.72
Discontinued operations		—			—			0.10

Net Income (loss)	$	(4.54	)	$	(0.95	)	$	0.82

Weighted average number of shares used in computation of earnings (loss) per share attributable to the Company’s stockholders:
Basic		45,431			45,431			45,431

Diluted		45,431			45,431			45,452

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	Year Ended December 31,
	2012			2011			2010
Statements of Operations Percentage Data:
Revenues:
Electricity		63.7	%		74.1	%		78.2	%
Product		36.3			25.9			21.8

		100.00			100.00			100.00

Cost of revenues:
Electricity		74.7			75.4			83.0
Product		72.4			67.2			65.4

		73.9			73.2			79.2

Gross margin:
Electricity		25.3			24.6			17.0
Product		27.6			32.8			34.6

		26.1			26.8			20.8
Operating expenses:
Research and development expenses		1.2			2.0			2.7
Selling and marketing expenses		3.1			3.7			3.6
General and administrative expenses		5.4			6.4			7.4
Impairment charges		46.0			0.0			0.0
Write-off of unsuccessful exploration activities		0.5			0.0			0.8

Operating income (loss)		(30.1	)		14.6			6.3
Other income (expense):
Interest income		0.2			0.3			0.1
Interest expense, net		(12.4	)		(15.9	)		(10.8	)
Foreign currency translation and transaction gains (losses)		0.0			(0.3	)		0.4
Income attributable to sale of tax benefits		2.0			2.6			2.3
Gain on acquisition of controlling interest		0.0			0.0			9.9
Other non-operating income, net		0.1			0.2			0.0

Income (loss) from continuing operations, before income taxes and equity in income (losses) of investees		(40.2	)		1.5			8.2
Income tax benefit (provision)		0.7			(11.1	)		0.3
Equity in income (losses) of investees, net		(0.5	)		(0.2	)		0.3

Income (loss) from continuing operations		(40.0	)		(9.8	)		8.8
Discontinued operations:
Income from discontinued operations, net of related tax		0.0			0.0			0.0
Gain on sale of a subsidiary in New Zealand, net of related tax		0.0			0.0			1.2

Net income (loss)		(40.0	)		(9.8	)		10.0
Net loss (income) attributable to noncontrolling interest		(0.1	)		(0.1	)		0.0

Net income (loss) attributable to the Company’s stockholders		(40.1	)%		(9.9	)%		10.0	%

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Comparison of the Year Ended December 31, 2012 and the Year Ended December 31, 2011

Total Revenues

Total revenues for the year ended December 31, 2012 were $514.4 million, compared to $437.0 million for the year ended December 31, 2011, which represented a 17.7% increase in total revenues. This increase was principally attributable to our Product Segment, in which revenues increased by 65.1% over the same period in 2011, principally due to a single order of $130.0 million referred to below, which we received in 2011.

Electricity Segment

Revenues attributable to our Electricity Segment for the year ended December 31, 2012 were $327.5 million, compared to $323.8 million for the year ended December 31, 2011, which represented a 1.1% increase in such revenues. This increase was primarily due to: (i) $23.5 million in revenues from our Tuscarora and McGinness Hills power plants, which commenced commercial operations in January 2012 and July 2012, respectively; (ii) a $3.2 million net increase in revenues from other power plants; and (iii) a net gain of $2.2 million on derivative contracts on oil and natural gas prices, which are described under “Recent Developments” in Item 1 — “Business”. This increase was offset by a $25.2 million decrease resulting from the impact of low natural gas prices on the energy rates in our SO#4 PPAs in California, which in the beginning of May 2012 changed from a fixed rate to a variable rate that is subject to the impact of fluctuations in natural gas prices. The generation of power in our power plants increased by 7.3% from 3,854,123 MWh in the year ended December 31, 2011 to 4,134,789 MWh in the year ended December 31, 2012. Revenues derived from the North Brawley power plant were $15.7 million and $15.3 million, respectively, in the years ended December 31, 2012 and 2011.

Product Segment

Revenues attributable to our Product Segment for the year ended December 31, 2012 were $186.9 million, compared to $113.2 million for the year ended December 31, 2011, which represented a 65.1% increase. The increase in our Product Segment revenues reflects the increase in new customer orders that we secured in 2011 and 2012, largely attributable to the $130.0 million order we received from Mighty River Power Limited for the Ngatamariki Geothermal Field in New Zealand, which is expected to be completed in 2013.

Total Cost of Revenues

Total cost of revenues for the year ended December 31, 2012 was $380.0 million, compared to $320.1 million for the year ended December 31, 2011, which represented a 18.7% increase. This was primarily due to the increase in cost of revenues from our Product Segment. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2012 was 73.9%, compared to 73.2% for the year ended December 31, 2011.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2012 was $244.6 million, compared to $244.0 million for the year ended December 31, 2011, which represented a 0.2% increase. This slight increase despite the additional cost of revenues from our new power plants, Tuscarora and McGinness Hills which commenced commercial operations in January 2012 and July 2012, respectively, is the result of lower maintenance costs in most of our power plants and specifically at our North Brawley power plant, where we incurred costs of $29.2 million associated with operating and maintaining the plant in the year ended December 31, 2012, compared to $41.8 million in the year ended December 31, 2011. We were able to lower such costs because we were able to improve our operating efficiencies, particularly in the maintenance of our well fields. Cost of revenues for the year ended December 31, 2012 includes $3.3 million of a net proceeds 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. Although we paid this amount we appealed the decision of the State of Nevada in January 2013 and we believe it is likely that our appeal will be successful, in whole or in part. The cost per MWh for the

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year ended December 31, 2012, decreased compared to the year ended December 31, 2011. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2012 was 74.7%, compared to 75.4% for the year ended December 31, 2011.

Product Segment

Total cost of revenues attributable to our Product Segment for the year ended December 31, 2012 was $135.3 million, compared to $76.1 million for the year ended December 31, 2011, which represented a 77.9% increase. This increase is attributable to a significant increase in product revenues, as described above. As a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment for the year ended December 31, 2012 was 72.4%, compared to 67.2% for the year ended December 31, 2011. This increase is mainly attributable to: (i) the recognition of revenues in the amount of $3.0 million in the year ended December 31, 2012, compared to $12.1 million in the year ended December 31, 2011, relating to an experimental REG plant specifically designed to use the residual energy from the vaporization process at LNG regasification terminals in Spain in the year ended December 31, 2012, with virtually no associated cost of revenues (since the related costs were included in research and development costs in previous years); (ii) a different product mix; and (iii) different margins in the various sales contracts. Excluding the impact of the revenues relating to the LNG energy recovery unit in Spain, the Product Segment total cost of revenues as a percentage of total Product Segment revenues for the year ended December 31, 2012 would have been 74.0%, compared to 75.2% for the year ended December 31, 2011.

Research and Development Expenses

Research and development expenses for the year ended December 31, 2012 were $6.1 million, compared to $8.8 million for the year ended December 31, 2011, which represented a 30.6% decrease. This decrease was primarily attributable to the costs incurred in the year ended December 31, 2011 in respect of an experimental REG plant specifically designed to use the residual energy from the vaporization process at LNG regasification terminals which was completed in 2011. The research and development expenses are net of grants from the DOE in the amount of $0.7 million and $1.1 million for the years ended December 31, 2012 and 2011, respectively, with respect to the EGS project.

Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2012 were $16.1 million, compared to $16.2 million for the year ended December 31, 2011, which represented a 0.5% decrease. The decrease resulted from a $1.7 million termination fee to NV Energy for the year ended December 31, 2011, as part of the termination agreement of the PPA and joint operating agreement for the Carson Lake geothermal project, offset by additional selling and marketing expenses associated with the increased Product Segment revenues. Selling and marketing expenses for the year ended December 31, 2012 constituted 3.1% of total revenues for such year, compared to 3.7% for the year ended December 31, 2011.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2012 were $28.3 million, compared to $27.9 million for the year ended December 31, 2011, which represented a 1.4% increase. General and administrative expenses for the year ended December 31, 2012, constituted 5.4% of total revenues for such year, compared to 6.4% for the year ended December 31, 2011.

Impairment Charges

Impairment charges for the year ended December 31, 2012 were $236.4 million. There were no impairment charges for the year ended December 31, 2011.

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We evaluate long-lived assets, including power plants, for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Such evaluations include estimates of future cash flows. If actual cash flows differ significantly from our current estimates, a material impairment charge may be required in the future.

During the fourth quarter of 2012, our North Brawley power plant was tested for recoverability due to the low output and higher than expected operating costs and was written down to a fair value of $32.0 million. The impairment loss of $229.1 million is presented in our consolidated statement of operations and comprehensive income (loss) under “Impairment Charges”.

During the third quarter of 2012, our OREG 4 power plant was tested for recoverability due to continued low output and was written down to a fair value of $3.6 million. The impairment loss of $7.3 million is presented in our consolidated statement of operations and comprehensive income (loss) under “Impairment Charges”.

For more details, see Note 7 to our consolidated financial statements set forth in Item 8 of this annual report.

Write-off of Unsuccessful Exploration Activities

Write-off of unsuccessful exploration activities for the year ended December 31, 2012 was $2.6 million. This represented the write-off of exploration costs (including land costs) related to five exploration sites in Nevada that we determined in the year ended December 31, 2012 would not support commercial operations. There were no write-offs of unsuccessful exploration activities for the year ended December 31, 2011.

Operating Income (Loss)

Operating loss for the year ended December 31, 2012 was $155.1 million, compared to operating income of $64.0 million for the year ended December 31, 2011. The operating loss was principally attributable to the impairment charges in the total amount of $236.4 million, as described above, partially offset by an increase in our gross margin. Operating loss attributable to our Electricity Segment for the year ended December 31, 2012 was $185.4 million, compared to operating income of $45.1 million for the year ended December 31, 2011. Operating income attributable to our Product Segment for the year ended December 31, 2012 was $30.3 million, compared to $18.9 million for the year ended December 31, 2011.

Interest Expense, Net

Interest expense, net, for the year ended December 31, 2012 was $64.1 million, compared to $69.5 million for the year ended December 31, 2011, which represented a 7.8% decrease. This $5.4 million decrease was primarily due to a $16.4 million loss, in the year ended December 31, 2011, on interest rate lock transactions, relating to the OFC 2 Senior Secured Notes, which were not accounted for as hedge transactions and an increase of $0.3 million in interest capitalized to projects as a result of increased aggregate investment in projects under construction, partially offset by additional interest expense mainly as a result of the issuance of Series A Senior Secured Notes in October 2011 by OFC 2, the full year impact in 2012 of the issuance of the Senior Unsecured Bonds in February 2011, and the $1.8 million of costs associated with the early repayment of part of the DEG loan in November 2012, as described below under “Liquidity and Capital Resources”.

Income Attributable to Sale of Tax Benefits

Income attributable to the sale of tax benefits to institutional equity investors (as described in “OPC Transaction” below) for the year ended December 31, 2012 was $10.1 million, compared to $11.5 million for the year ended December 31, 2011. This income represents the value of PTCs and taxable income or loss generated by OPC and allocated to the investors. The decrease was due to lower depreciation for tax purposes as a result of declining depreciation rates utilizing MACRS.

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Income Taxes

Income tax benefit for the year ended December 31, 2012 was $3.5 million, compared to an income tax provision of $48.5 million for the year ended December 31, 2011. The decrease in income tax provision primarily resulted from the decrease in income before taxes.

For the year ended December 31, 2012 and 2011, we recorded a valuation allowance in the amount of approximately $19.4 million and $61.5 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, 2012 we had U.S. federal NOLs in the amount of approximately $267.6 million, state NOLs in the amount of approximately $193.4 million, and unutilized tax credits of approximately $70.4 million, all of which can be utilized over 20 years. The related deferred tax assets totaled approximately $176.1 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 $80.9 million was recorded against the U.S. deferred tax assets as of December 31, 2012 as, at that point in time, we believed it is more likely than not that the deferred tax assets will not be realized. If sufficient evidence of our ability to generate taxable income is established in the future, we may be required to reduce this valuation allowance, resulting in income tax benefits in our consolidated statement of operations.

Net Income (Loss)

Net loss for the year ended December 31, 2012 was $206.0 million, compared to $42.7 million for the year ended December 31, 2011. The increase in net loss of $163.3 million was principally attributable to a $219.1 million decrease in operating income, offset by: (i) a $52.0 million decrease in income tax provision; and (ii) a $5.4 million decrease in interest expense, net.

Comparison of the Year Ended December 31, 2011 and the Year Ended December 31, 2010

Total Revenues

Total revenues for the year ended December 31, 2011 were $437.0 million, compared to $373.2 million for the year ended December 31, 2010, which represented a 17.1% increase in total revenues. This increase was attributable to both our Electricity and Product Segments whose revenues increased by 11.0% and by 39.0%, respectively, over the same period in 2010.

Electricity Segment

Revenues attributable to our Electricity Segment for the year ended December 31, 2011 were $323.8 million, compared to $291.8 million for the year ended December 31, 2010, which represented an 11.0% increase in such revenues. This increase was due to: (i) an increase in the electricity rates in our Amatitlan and Puna power plants, which resulted in an increase in the average rate of our electricity portfolio from $78 per MWh in the year ended December 31, 2010 to $83 per MWh in the year ended December 31, 2011; and (ii) increased electricity generation of our power plants from 3,762,283 MWh in the year ended December 31, 2010 to 3,918,156 MWh in the year ended December 31, 2011, an increase of 4.1%. The most significant contributors to the increase in our electricity generation were: (i) an increase in the generation of the Puna power plant due to repair work that was completed in the second quarter of 2010; (ii) the consolidation of the Mammoth complex, effective August 2, 2010, with revenues of $19.0 million in the year ended December 31, 2011, compared to $7.6 million in the period from August 2, 2010 to December 31, 2010, which resulted from the acquisition of the remaining 50% interest in Mammoth Pacific in August 2010; and (iii) an increase in generation of our REG facilities due to the addition of one plant and a higher availability of the pipeline providing the heat to most of our REG power plants. The revenues derived from our North Brawley power plant were $15.3 million and $15.0 million, respectively, in the years ended December 31, 2011 and 2010.

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Product Segment

Revenues attributable to our Product Segment for the year ended December 31, 2011 were $113.2 million, compared to $81.4 million for the year ended December 31, 2010, which represented a 39.0% increase in such revenues. The increase in our Product Segment revenues reflects the increase in new customer orders that we secured in the first half of 2011, and the recognition of $12.1 million of revenues relating to an LNG energy recovery unit in Spain in the year ended December 31, 2011 (see “Research and Development Expenses” below).

Total Cost of Revenues

Total cost of revenues for the year ended December 31, 2011 was $320.1 million, compared to $295.6 million for the year ended December 31, 2010, which represented an 8.3% increase. This increase was attributable to both our Electricity and Product Segments cost of revenues. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2011 was 73.2%, compared to 79.2% for the year ended December 31, 2010.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2011 was $244.0 million, compared to $242.3 million for the year ended December 31, 2010, which represented a 0.7% increase. Costs incurred in operating and maintaining the North Brawley power plant in the year ended December 31, 2011 were slightly higher than in the year ended December 31, 2010 ($41.8 million and $39.6 million, respectively). The cost per MWh for the year ended December 31, 2011 slightly decreased, compared to the year ended December 31, 2010, as a result of lower maintenance costs, which were offset by: (i) the slightly higher costs in the North Brawley power plant, as described above; and (ii) increased depreciation costs in the Mammoth complex, resulting from the program to repower the complex by replacing part of the old units with new equipment. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2011 was 75.4%, compared to 83.0% for the year ended December 31, 2010. This decrease in electricity cost of revenues as a percentage of total electricity revenues was due to the 11.0% increase in electricity revenues, which outpaced the 0.7% increase in electricity cost of revenues.

Product Segment

Total cost of revenues attributable to our Product Segment for the year ended December 31, 2011 was $76.1 million, compared to $53.3 million for the year ended December 31, 2010, which represented a 42.8% increase. This increase was attributable to the increase in Product Segment revenues, as described above. As a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment increased from 65.4% for the year ended December 31, 2010 to 67.2% for the year ended December 31, 2011. This increase was mainly attributable to a different product mix and different margins in the various sales contracts. The increase was partially offset by the impact of revenues of $12.1 million relating to an experimental REG plant specifically designed to use the residual energy from the vaporization process at LNG regasification terminals in Spain with virtually no associated cost of revenues, as these costs had been included in our research and development expenses in previous years.

Research and Development Expenses

Research and development expenses for the year ended December 31, 2011 was $8.8 million, compared to $10.1 million for the year ended December 31, 2010, which represented a 13.0% decrease. This decrease was primarily attributable to the decrease in costs related to an experimental REG plant specifically designed to use the residual energy from the vaporization process at LNG regasification terminals. These costs included developing and building a unit at a customer’s premises in Spain and were incurred through the second quarter of 2010. The research and development expenses are net of grants from the DOE with respect to the EGS project in the amount of $1.1 million and $0.7 million for the years ended December 31, 2011 and 2010, respectively.

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Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2011 were $16.2 million, compared to $13.4 million for the year ended December 31, 2010, which represented a 20.5% increase. The increase was due primarily to the increase in Product Segment revenues and to a $1.7 million termination fee to NV Energy as part of the termination agreement of the PPA and joint operating agreement for the Carson Lake geothermal project. Selling and marketing expenses for the year ended December 31, 2011 constituted 3.7% of total revenues for such period, compared to 3.6% for the year ended December 31, 2010.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2011 were $27.9 million, compared to $27.4 million for the year ended December 31, 2010, which represented a 1.6% increase. General and administrative expenses for the year ended December 31, 2011, constituted 6.4% of total revenues for such year, compared to 7.4% for the year ended December 31, 2010.

Write-off of Unsuccessful Exploration Activities

Write-off of unsuccessful exploration activities for the year ended December 31, 2010 was $3.1 million. This represented the write-off of exploration costs related to the Gabbs Valley exploration project in Nevada, which we determined in the second quarter of 2010 would not support commercial operations. There were no write-offs of unsuccessful exploration activities for the year ended December 31, 2011.

Operating Income

Operating income for the year ended December 31, 2011 was $64.0 million, compared to $23.6 million for the year ended December 31, 2010, an increase of $40.4 million. This increase was principally attributable to an increase in our gross margin due to the increase in revenues, as described above, and the absence of any write-off of unsuccessful exploration activities in the year ended December 31, 2011. Operating income attributable to our Electricity Segment for the year ended December 31, 2011 was $46.2 million, compared to $12.8 million for the year ended December 31, 2010. Operating income attributable to our Product Segment for the year ended December 31, 2011 was $18.9 million, compared to $10.8 million for the year ended December 31, 2010.

Interest Expense, Net

Interest expense, net, for the year ended December 31, 2011 was $69.5 million, compared to $40.5 million for the year ended December 31, 2010, which represented a 71.6% increase. The $29.0 million increase was primarily due to: (i) a $16.4 million loss in the year ended December 31, 2011 on interest rate lock transactions relating to the OFC 2 Senior Secured Notes, which were not accounted for as hedge transactions; and (ii) the issuance of Senior Unsecured Bonds in August 2010 and February 2011, as discussed elsewhere in this Item. The increase was partially offset by: (i) an increase of $2.2 million in interest capitalized to projects as a result of increased aggregate investment in projects under construction; and (ii) a decrease in interest expense as a result of principal repayments.

Foreign Currency Translation and Transaction Gains (Losses)

Foreign currency translation and transaction losses for the year ended December 31, 2011 were $1.4 million, compared to gains of $1.6 million for the year ended December 31, 2010. The $3.0 million variance was primarily due to losses on forward foreign exchange transactions for the year ended December 31, 2011, which were not accounted for as hedge transactions, compared to gains in the year ended December 31, 2010.

Income Attributable to Sale of Tax Benefits

Income attributable to the sale of tax benefits to institutional equity investors (as described in “OPC Transaction” below) for the year ended December 31, 2011 was $11.5 million, compared to $8.7 million for the

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year ended December 31, 2010. This income represents the value of PTCs and taxable income or loss generated by OPC and allocated to the investors. The increase resulted from the sale of Class B membership units of OPC LLC to JPM on February 3, 2011.

Gain on Acquisition of Controlling Interest

Gain on acquisition of controlling interest for the year ended December 31, 2010 was $36.9 million. This gain related to the acquisition of the remaining 50% interest in Mammoth Pacific. The acquisition-date fair value of the previous 50%-equity interest was $64.9 million. In the year ended December 31, 2010, we recognized a pre-tax gain of $36.9 million ($22.4 million after tax), which is equal to the difference between the acquisition-date fair value of the initial investment in Mammoth Pacific and the acquisition-date carrying value of such investment. There was no gain on acquisition of controlling interest for the year ended December 31, 2011.

Income Taxes

Income tax provision for the year ended December 31, 2011 was $48.5 million, compared to an income tax benefit of $1.1 million for the year ended December 31, 2010.

In the year ended December 31, 2011, we recorded valuation allowance in the amount of approximately $61.5 million against our U.S. deferred tax assets in respect of NOL carryforwards and unutilized tax credits (PTCs and ITCs). As of December 31, 2011 we had U.S. federal NOL in the amount of approximately $349.5 million, state NOLs in the amount of approximately $159.0 million, and unutilized tax credits of approximately $61.9 million, all of which can be utilized over 20 years. The related deferred tax assets totaled approximately $192.5 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 $61.5 million was recorded against the U.S. deferred tax assets as of December 31, 2011 as, at that point in time, we believed it is more likely than not that the deferred tax assets will not be realized. If sufficient evidence of our ability to generate taxable income is established in the future, we may be required to reduce this valuation allowance, resulting in income tax benefits in our consolidated statement of operations.

Income (loss) from Continuing Operations

Loss from continuing operations for the year ended December 31, 2011 was $42.7 million, compared to income of $32.9 million for the year ended December 31, 2010. This decrease of $75.6 million in income from continuing operations was principally attributable to: (i) the increase of $49.6 million in tax provision resulting from the valuation allowance discussed above; (ii) a $36.9 million gain related to the acquisition of controlling interest in the year ended December 31, 2010; (iii) a $29.0 million increase in interest expense, net; and (iv) a $2.9 million decrease in foreign currency transaction and translation gains. This was partially offset by a $40.4 million increase in operating income.

Discontinued Operations

In January 2010, a former shareholder of GDL exercised a call option to purchase from us our shares in GDL for approximately $2.8 million. We did not exercise our right of first refusal, and therefore we transferred our shares in GDL to the former shareholder. As a result, we recorded an after-tax gain of $4.3 million in the year ended December 31, 2010. The operations of GDL have been included in discontinued operations for all periods prior to the sale of GDL in January 2010. We did not have any gain from discontinued operations in the year ended December 31, 2011.

Net Income (Loss)

Net loss for the year ended December 31, 2011 was $42.7 million, compared to net income of $37.2 million for the year ended December 31, 2010, which represents a decrease of $79.9 million. This decrease in net income was principally attributable to the decrease in income from continuing operations in the amount of $75.6 million, as discussed above.

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Liquidity and Capital Resources

Our principal sources of liquidity have been derived from cash flows from operations, the issuance of our common stock in public and private offerings, proceeds from third party debt in the form of borrowings under credit facilities and private offerings, issuance by OFC, OrCal and OFC 2 of their respective Senior Secured Notes, project financing (including the Puna lease and the OPC Transaction described below), and cash grants we received under the ARRA. We have utilized this cash to develop and construct power generation plants, to fund our acquisitions, and to meet our other cash and liquidity needs.

As of December 31, 2012, we had access to the following sources of funds: (i) $69.6 million in cash, cash equivalents and a short-term bank deposit; and (ii) $184.9 million of unused corporate borrowing capacity under existing lines of credit with different commercial banks.

Our estimated capital needs for 2013 include approximately $237.0 million for capital expenditures on new projects under development or construction, exploration activity, operating projects, and machinery and equipment, as well as $68.3 million for debt repayment.

We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) positive cash flows from our operations; (iii) the proceeds we received in January 2013 from the ORTP Transaction described below; (iv) future project financing and refinancing (including construction loans); and (v) cash grants available to us under the ARRA in respect of new projects that will be placed in service before the end of 2013. Management believes that these sources will address our anticipated liquidity, capital expenditures, and other investment requirements.

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

On February 13, 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 believe 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 we do not believe that there will be an event of default by OFC. As of December 31, 2012 (the last measurement date of the covenants), the actual historical 12-month DSCR was 1.28. As of December 31, 2012, there were $114.1 million of OFC Senior Secured Notes outstanding.

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In February 2013, we acquired from OFC noteholders OFC Senior Secured Notes with an outstanding aggregate principal amount of $12.8 million and we will recognize a gain of $1.1 million in the first quarter of 2013.

OrCal Geothermal Senior Secured Notes — Non-Recourse

On December 8, 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- and BB as of December 31, 2012 and March 8, 2013, respectively, 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. As of December 31, 2012, the actual historical 12-month DSCR was 1.36. As of December 31, 2012, there were $76.5 million of OrCal Senior Secured Notes outstanding.

OFC 2 Senior Secured Notes — Limited Recourse during Construction and Non-Recourse Thereafter

On September 23, 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 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 include certain specified conditions required by the DOE in connection with its guarantee of the OFC 2 Senior Secured Notes.

On October 31, 2011, the OFC 2 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 $147.4 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.

Issuance of the Series B Notes is dependent on the Jersey Valley power plant reaching certain operational targets in addition to the other conditions precedent noted above. If issued, the aggregate principal amount of the Series B Notes will not exceed $28.0 million, and such proceeds would be used to finance a portion of the construction costs of Phase I of the Jersey Valley power plant.

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The OFC 2 Issuers have sole discretion regarding whether to commence construction of Phase II of any of the Jersey Valley, McGinness Hills and Tuscarora power plants. If Phase II construction is undertaken for any of the power plants, the OFC 2 Issuers may issue Phase II tranches of Notes, comprised of one or more of Series C Notes, Series D Notes, Series E Notes and Series F Notes, to finance a portion of the construction costs of such Phase II of any facility. The aggregate principal amount of all Phase II Notes may not exceed $170.0 million. The aggregate principal amount of each series of Notes comprising a Phase II tranche will be determined by the OFC 2 Issuers in their sole discretion provided that certain financial ratios are satisfied pursuant to the terms of the Note Purchase Agreement and subject to the aggregate limit noted above.

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 and projected quarterly DSCR requirement of at least 1.2 (on a blended basis for all of the OFC 2 power plants) and 1.5 on a pro forma basis (giving effect to the distributions). As of December 31, 2012 (the last measurement date of the covenants), the historical actual DSCR for the quarter ended December 31, 2012 was 2.69 and the pro-forma 12-month DSCR was 2.13.

We provided a guarantee in connection with the issuance of the Series A Notes, and will provide a guarantee in connection with the issuance of each other Series of OFC 2 Senior Secured Notes, which will be available to be drawn upon if certain trigger events occur. 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 financed by such OFC 2 Senior Secured Notes reaches completion and meets certain operational performance levels. A demand on our 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 our guarantee based on the other trigger event is not so limited.

As of December 31, 2012, there were $150.5 million of OFC 2 Senior Secured Notes outstanding.

Olkaria III Finance Agreement with OPIC — Limited Recourse during Construction and Non-Recourse Thereafter

On August 23, 2012, OrPower 4, one of our subsidiaries, entered into a finance agreement with 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 our 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 on November 9, 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 up to $180.0 million will be used to fund the construction and well field drilling for the expansion of the Olkaria III geothermal power complex (Plant 2). On November 9, 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.

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•

Tranche III is a stand-by tranche in an aggregate principal amount of up to $45.0 million, and will be made available to OrPower 4 in the event it elects, in its discretion, to construct a further expansion of the Olkaria III complex (Plant 3). Terms and conditions for Tranche III of the OPIC Loan will be agreed upon by OPIC and OrPower 4 in subsequent documentation.

The interest rate on both Tranche I and Tranche II is variable from the date of disbursement until a conversion date selected by OrPower 4, whereupon interest on each Tranche will convert to a fixed rate. The interest rate as of December 31, 2012 was 2.92%. Interest, whether floating or fixed, will be payable quarterly in arrears on each March 15, June 15, September 15 and December 15, commencing with the first such date following the respective disbursement of a Tranche. OrPower 4 is required to select a conversion date that will be within 180 days of the commercial operation date of Plant 2.

The applicable Tranche interest rate will be determined at the time of the actual disbursement of loan proceeds based upon, and in connection with the issuance of certificates of participation in the OPIC Loan. The payment of principal and interest on the certificates of participation is fully guaranteed by OPIC, and is backed by the full faith and credit of the U.S. government.

The final maturity of Tranche I and Tranche II is approximately 18 years.

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.

The repayment of the remaining outstanding DEG Loan (see “Full-Recourse Third-Party Debt” below) in the amount of approximately $51.3 million as of November 9, 2012, 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 will become effective on December 15, 2014.

As of December 31, 2012, $220.0 million of the above loan was outstanding.

Amatitlan Loan — Non-Recourse

In May 2009, Ortitlan, one of our subsidiaries, entered into a note purchase agreement in an aggregate principal amount of $42.0 million which refinanced its investment in the 20 MW geothermal power plant located in Amatitlan, Guatemala. The loan was provided by TCW Global Project Fund II, Ltd. (TCW). The loan bears interest at a rate of 9.83%, will mature on June 15, 2016, and is payable in 28 quarterly installments. There are various restrictive covenants under the loan, which include: (i) a projected 12-month DSCR of not less than 1.2;

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and (ii) a long-term debt to equity ratio not to exceed 4.0 (both of which are measured quarterly). If Ortitlan fails to comply with these financial ratios it will be prohibited from making distributions to its shareholders. In addition, subject to certain cure rights, such failure will constitute an event of default. As of December 31, 2012, the projected 12-month DSCR was 1.58 and the debt to equity ratio was 2.51. As of December 31, 2012, $34.3 million of this loan was outstanding.

Full-Recourse Third-Party Debt

Union Bank. On February 7, 2012, Ormat Nevada, our wholly owned subsidiary entered into an amended and restated credit agreement with Union Bank. Under the amended and restated agreement, the credit termination date was extended from February 15, 2012 to February 7, 2014 and the aggregate amount available under the credit agreement was increased from $39.0 million to $50.0 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.

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, 2012: (i) the actual 12-month debt to EBITDA ratio was 2.38; (ii) the 12-month DSCR was 3.26; and (iii) the distribution leverage ratio was 1.19. 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, 2012, letters of credit in the aggregate amount of $42.5 million remain issued and outstanding under this credit agreement with Union Bank.

Credit Agreements. We also have credit agreements with five other commercial banks for an aggregate amount of $395.8 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 $265.0 million; and (ii) the issuance of one or more letters of credit in the amount of up to $130.8 million. The credit agreements mature between June 2013 and December 2014. 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, 2012, loans in the total amount of $73.6 were outstanding, and letters of credit with an aggregate stated amount of $141.3 million were issued and outstanding under these credit agreements. The $73.6 million in loans are for terms of three months or less and bear interest at a weighted average rate of 2.71%.

Term Loans. We have a $20.0 million term loan with a group of institutional investors, which matures on July 16, 2015, is payable in 12 semi-annual installments commencing January 16, 2010, and bears interest of 6.5%. As of December 31, 2012, $11.0 million was outstanding under this loan.

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, 2012, $16.0 million was outstanding under this loan.

We have a $20.0 million term loan with a group of institutional investors, which matures on November 16, 2016, is payable in ten semi-annual installments commencing May 16, 2012, and bears interest of 5.75%. As of December 31, 2012, $16.6 million was outstanding under this loan.

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We have a $50.0 million term loan with a commercial bank, which matures on November 10, 2014, is payable in ten semi-annual installments commencing May 10, 2010, and bears interest at 6-month LIBOR plus 3.25%. As of December 31, 2012, $20.0 million was outstanding under this loan.

Senior Unsecured Bonds. We have an aggregate principal amount of approximately $250.0 million of Senior Unsecured Bonds issued and outstanding. We issued approximately $142.0 million of these bonds in August 2010 and an additional $107.5 million in February 2011. Subject to early redemption, the principal of the bonds is repayable in a single bullet payment upon the final maturity of the bonds on August 1, 2017. The bonds bear 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 of 6.75%.

Loan Agreement 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%. Currently, $47.4 million is outstanding under the DEG Loan (out of which $32.5 million bears interest at a fixed rate).

On October 31, 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”). 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; (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 as a result of OrPower 4’s execution of the OPIC Finance Agreement and its obligations thereunder.

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 30% 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 7.0; and (iii) dividend distributions not to exceed 35% of net income in any calendar year. As of December 31, 2012: (i) total equity was $702.2 million and the actual equity to total assets ratio was 34.2%; and (ii) the 12-month debt, net of cash, cash equivalents, marketable securities and short-term bank deposits to Adjusted EBITDA ratio was 4.73. During the year ended December 31, 2012, we distributed interim dividends in an aggregate amount of $3.6 million. Although we reported a net loss for the year, under the credit agreements, the loan agreements, and the trust instrument governing the bonds we can distribute interim dividends on the basis of our estimate of our net income for the year. Since we incurred a loss for the year ended December 31, 2012, an adjustment of $3.6 million will be made in the next fiscal year in which we distribute a dividend. 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.

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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.

Letters of Credit

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, 2012, letters of credit in the aggregate amount of $217.8 million remained issued and outstanding (out of which $183.8 million were issued under the credit agreements with Union Bank and five of the commercial banks as described under “Full-Recourse Third Party Debt” and $34.0 million were issued under non-committed lines of credit).

Puna Power Plant Lease Transactions

On May 19, 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 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.

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.

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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.

The Class B membership units are provided with 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.

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 ORTP of 25% of the value of PTCs generated by the portfolio over time. The additional payments are expected to be made until December 31, 2016 and total approximately $8.7 million.

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 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% (allocation of income and loss) and 2.5% (allocation of cash) residual economic interest in OERP. The 5% and 2.5% residual interest commences on achievement by JPM of a contractually stipulated return that triggers the ORTP Flip Date. The actual ORTP Flip Date is not known with certainty. This residual 5% and 2.5% interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments.

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% 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.

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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 $7.3 million as of December 31, 2012. 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 22, 2011	$	0.05	March 15, 2011	March 24, 2011
May 4, 2011	$	0.04	May 18, 2011	May 25, 2011
August 3, 2011	$	0.04	August 16, 2011	August 25, 2011
May 8, 2012	$	0.04	May 21, 2012	May 30, 2012
August 1, 2012	$	0.04	August 14, 2012	August 23, 2012

Historical Cash Flows

The following table sets forth the components of our cash flows for the relevant periods indicated:


	Year Ended December 31,
	2012			2011			2010
	(In thousands)
Net cash provided by operating activities	$	89,471		$	132,734		$	101,403
Net cash used in investing activities		(100,790	)		(341,002	)		(203,820	)
Net cash provided by (used in) financing activities		(21,939	)		225,339			138,925
Net change in cash and cash equivalents		(33,258	)		17,071			36,508

For the Year Ended December 31, 2012

Net cash provided by operating activities for the year ended December 31, 2012 was $89.5 million, compared to $132.7 million for the year ended December 31, 2011. The net decrease of $43.2 million resulted primarily from: (i) an increase in net loss from $42.7 million in the year ended December 31, 2011 to $206.0 million in the year ended December 31, 2012, as described above; (ii) a decrease in deferred income tax provision, net of $11.3 million in the year ended December 31, 2012, compared to an increase of $38.1 million in the year ended December 31, 2011; and (iii) a decrease in billing in excess of costs and estimated earnings on uncompleted contracts, net of $13.3 million in our Product Segment in the year ended December 31, 2012, compared to an increase of $32.1 million in the year ended December 31, 2011, as a result of timing in billing of our customers. Such decrease was partially offset by an impairment charge of $236.4 million, as described above.

Net cash used in investing activities for the year ended December 31, 2012 was $100.8 million, compared to $341.0 million for the year ended December 31, 2011. The principal factors that affected our net cash used in investing activities during the year ended December 31, 2012 were capital expenditures of $233.0 million, primarily for our facilities under construction offset by: (i) a cash grant in the amount of $119.2 million received in the year ended December 31, 2012 from the U.S. Treasury under Section 1603 of the ARRA relating to the enhancement of our Puna geothermal complex and to our Jersey Valley, Tuscarora, and McGinness Hills geothermal power plants; and (ii) a net decrease of $18.8 million in marketable securities.

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Net cash used in financing activities for the year ended December 31, 2012 was $21.9 million, compared to net cash provided by financing activities of $225.3 million for the year ended December 31, 2011. The principal factors that affected the net cash used in financing activities during the year ended December 31, 2012 were: (i) a net decrease of $140.4 million against our revolving lines of credit with commercial banks; (ii) the repayment of long-term debt in the amount of $74.5 million; (iii) $14.9 million of cash paid to the Class B membership units of OPC (see “OPC Transaction”); and (iv) the payment of a dividend to our shareholders in the amount of $3.6 million. This decrease was partially offset due to $214.1 million net proceeds from the disbursements of $85.0 million representing the full amount of Tranche I of the OPIC Loan, and $135.0 million from Tranche II of the OPIC Loan, as described above under “Non-Recourse and Limited-Recourse Third-Party Debt”.

For the Year Ended December 31, 2011

Net cash provided by operating activities for the year ended December 31, 2011 was $132.7 million, compared to $101.4 million for the year ended December 31, 2010. The net increase of $31.3 million resulted primarily from: (i) an increase of $9.7 million in depreciation and amortization, as described above; (ii) a gain on acquisition of controlling interest in the Mammoth complex of $36.9 million in the year ended December 31, 2010; (iii) a gain on sale of GDL of $6.3 million in the year ended December 31, 2010; (iv) an increase in deferred income tax provision, net of $38.1 million in the year ended December 31, 2011, compared to a decrease of $10.1 million in the year ended December 31, 2010; and (v) an increase in billing in excess of costs and estimated earnings on uncompleted contracts, net of $32.1 million in our Product Segment in the year ended December 31, 2011, compared to $8.7 million in the year ended December 31, 2010, as a result of timing in billing of our customers. Such increase was partially offset by: (i) a net loss of $42.7 million in the year ended December 31, 2011, compared to net income of $37.2 million in the year ended December 31, 2010, as described above, and (ii) an increase in accounts payable and accrued expenses of $5.5 million in the year ended December 31, 2011, compared to an increase of $9.7 million in the year ended December 31, 2010, as a result of timing of payments to our vendors.

Net cash used in investing activities for the year ended December 31, 2011 was $341.0 million, compared to $203.8 million for the year ended December 31, 2010. The principal factors that affected our net cash used in investing activities during the year ended December 31, 2011 were: (i) capital expenditures of $269.7 million, primarily for our facilities under construction; (ii) net increase of $50.6 million in restricted cash, cash equivalents and marketable securities as a result of the issuance of the OFC 2 Senior Secured Notes, and (iii) net increase of $17.5 million in marketable securities.

Net cash provided by financing activities for the year ended December 31, 2011 was $225.3 million, compared to $138.9 million for the year ended December 31, 2010. The principal factors that affected the net cash provided by financing activities during the year ended December 31, 2011 were: (i) the issuance of an aggregate amount of approximately $107.4 million of Senior Unsecured Bonds in February 2011; (ii) $141.1 million net proceeds from the issuance of the OFC 2 Senior Secured Notes; (iii) proceeds from the sale of all of the Class B membership units of OPC acquired on October 30, 2009 for a sale price of 24.9 million; and (iv) a net increase of $24.6 million against our revolving lines of credit with commercial banks; offset by: (i) the repayment of long-term debt in the amount of $48.4 million; (ii) $14.0 million of cash paid to the Class B membership units of OPC; and (iii) the payment of a dividend to our shareholders in the amount of $5.9 million.

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, excluding impairment of long-lived assets and including depreciation and amortization, interest and taxes attributable to our equity investments in the Mammoth complex. EBITDA and adjusted EBITDA are not measurements of financial performance or liquidity under 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 GAAP. EBITDA and adjusted EBITDA are

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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 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, 2012 was $185.7 million, compared to $166.7 million for the year ended December 31, 2011 and $164.3 million for the year ended December 31, 2010.

The following table reconciles net cash provided by operating activities to EBITDA and adjusted EBITDA, for the years ended December 31, 2012, 2011, and 2010:


	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Net cash provided by operating activities	$	89,471		$	132,734		$	101,403
Adjusted for:
Interest expense, net (excluding amortization of deferred financing costs)		57,711			65,920			37,590
Interest income		(1,201	)		(1,427	)		(343	)
Income tax provision (benefit)		(3,500	)		48,535			908
Adjustments to reconcile net income to net cash provided by operating activities (excluding depreciation and amortization)		(193,147	)		(79,060	)		22,586

EBITDA		(50,666	)		166,702			162,144
Impairment charges		236,377			—			—
Interest, taxes, depreciation and amortization attributable to the Company’s equity interest in Mammoth-Pacific L.P.		—			—			2,115

Adjusted EBITDA	$	185,711		$	166,702		$	164,259

Net cash used in investing activities	$	(100,790	)	$	(341,002	)	$	(203,820	)

Net cash provided by financing activities	$	(21,939	)	$	225,339		$	138,925

Capital Expenditures

Our capital expenditures primarily relate to two principal components: (i) the enhancement of our existing power plants; and (ii) the development and construction of new power plants.

We have estimated approximately $377.0 million in capital expenditures for construction of new projects that are still under construction, of which we have invested approximately $185.0 million as of December 31, 2012, we expect to invest $179.0 million of such total in 2013 and the remaining $13 million thereafter.

In addition, we estimate approximately $58.0 million in additional capital expenditures in 2013 to be allocated as follows: (i) $15.0 million in development of new projects; (ii) $26.0 million for enhancement of our operating power plants; (iii) $10.0 million in exploration activities in various leases for geothermal resources in which we have started the exploration activity; and (iv) $7.0 million in enhancement of our production facilities. In the aggregate, we estimate our total capital expenditures for 2013 to be approximately $237.0 million.

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.

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One market risk to which power plants are typically exposed is the volatility of electricity prices. 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) have fixed or escalating rate provisions that limit our exposure to changes in electricity prices. However, beginning in May 2012, the energy payments under the PPAs of the Heber 1 and 2 power plants, the Ormesa complex and the Mammoth complex have been 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, which in turn will reduce the variable energy rate that we may charge under the relevant PPA for these power plants. In addition, as described under the heading “Recent Developments” in Item 1 — “Business”, in May and July 2012, we entered into put transactions, and in October 2012, we entered into swap contracts to reduce our exposure to the price of natural gas, under these PPAs, until December 31, 2013. 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. Likewise, as described under “Recent Developments” in Item 1 — “Business”, in April 2012, we entered into swap contracts, and in September 2012, we entered into put transactions to reduce our exposure to the price of oil, under the 25 MW PPA of the Puna complex, until December 31, 2013.

As of December 31, 2012, 66.5% of our consolidated long-term debt bore a fixed rate and therefore was not subject to interest rate volatility risk. As of such date, 33.5%% of our long-term debt was in the form of a floating rate instrument, exposing us to changes in interest rates in connection therewith. As of December 31, 2012, $345.2 million of our long-term debt remained subject to some floating 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 and our portfolio of marketable securities are subject to market risk due to changes in interest rates. Fixed rate securities may have their market value adversely impacted due to a rise in interest rates, while floating rate securities may produce less income than expected if interest rates fall. Due in part to these factors, our future investment income may fall short of expectation due to changes in interest rates or we may suffer losses in principal if we are forced to sell securities that decline in market value due to changes in interest rates. However, because we classify our debt securities as “available-for-sale”, no gains or losses are recognized due to changes in interest rates unless such securities are sold prior to maturity or declines in fair value are determined to be other-than-temporary.

Another market risk to which we are exposed is primarily related to potential adverse changes in foreign currency exchange rates, 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 sale contract in the currency in which the expenses are incurred. Currently, we have forward and option 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.

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

129

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, 2012 and 2011 by a hypothetical 10% and calculating the resulting change in the fair values.

The results of the sensitivity analysis calculations as of December 31, 2012 and 2011 are presented below:


	Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates				Change in the Fair Value of
	As of December 31,						As of December 31,
Risk	2012			2011			2012		2011
	(In thousands)
NGI Price	$	(484	)	$	—		$	6,097	$	—	NGI Swap
NYMEX Heating Oil Price	$	(439	)	$	—		$	1,037	$	—	NYMEX HO2 Swap
ICE Brent Price	$	(122	)	$	—		$	41	$	—	ICE Brent Swap
NYMEX Heating Oil Price	$	790		$	—		$	2,988	$	—	NYMEX HO2 Fixed Rate Put
ICE Brent Price	$	135		$	—		$	429	$	—	ICE Brent Fixed Rate Put
Foreign Currency	$	(5,074	)	$	(2,044	)	$	7,503	$	2,637	Foreign Currency Forward Contracts
Interest Rate	$	(3,388	)	$	(4,226	)	$	3,557	$	4,477	Ormat Funding Corp. (“OFC”)
Interest Rate	$	(1,550	)	$	(2,113	)	$	1,650	$	2,196	Orcal Geothermal Inc. (“OrCal”)
Interest Rate	$	(5,600	)	$	(6,214	)	$	6,100	$	6,697	OFC 2 LLC (“OFC 2”)
Interest Rate	$	(540	)	$	(1,075	)	$	560	$	1,109	Loan from DEG
Interest Rate	$	(532	)	$	(1,026	)	$	468	$	1,072	Loan from TCW
Interest Rate	$	(5,477	)	$	(7,980	)	$	5,623	$	8,299	Senior Unsecured Bonds
Interest Rate	$	(401	)	$	(467	)	$	99	$	478	Loan from Institutional Investors

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 mitigating factors against any inflation risk. In connection with the Electricity Segment, inflation may directly impact an expense incurred for the operation of our projects, hence increasing the overall operating cost to us. 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 plant, 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 determined 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, hence increasing our operating costs in that segment. In this segment, it is more likely that we will be able to offset part or all of the inflationary impact through our project pricing. With respect to power plants that we construct 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. Overall, we believe that the impact of inflation on our business will not be significant.

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Contractual Obligations and Commercial Commitments

The following tables set forth our material contractual obligations as of December 31, 2012 (in thousands):


	Payments Due By Period
	Remaining Total		2013		2014		2015		2016		2017		Thereafter
Long-term liabilities principal	$	1,030,928	$	68,333	$	150,872	$	70,850	$	86,188	$	308,938	$	345,747
Interest on long-term liabilities⁽¹⁾		364,547		62,409		56,947		51,192		45,422		40,331		108,246
Future minimum operating lease		63,928		8,062		8,647		8,222		8,374		8,747		21,876
Benefits upon retirement⁽²⁾		19,237		5,495		591		229		1,319		2,166		9,437
Asset retirement obligation		19,289		—		—		—		—		—		19,289
Purchase commitments⁽³⁾		93,600		93,600		—		—		—		—		—

	$	1,591,529	$	237,899	$	217,057	$	130,493	$	141,303	$	360,182	$	504,595

⁽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 OPIC Loan due in 2030 is variable until it is converted to a fixed rate. Interest on the DEG Loan due in 2018 is fixed for $32.5 million as of December 31, 2012, at a rate of 6.9% and variable on the remaining balance (which as of December 31, 2012 was $14.9 million). Interest on the Amatitlan Loan due in 2016 is fixed at a rate of 9.83%. Interest on a loan from institutional investors due in 2015 is fixed at a rate of 6.5%. Interest on a loan from institutional investors due in 2016 is fixed at a rate of 5.75%. Interest on the Senior Unsecured Bonds due in 2017 is fixed at a rate of 7%. 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, 2013, total obligations related to such supplier agreements were approximately $93.6 million (approximately $42.5 million of which relate to construction-in-process). All such obligations are payable in 2013.

The above table does not reflect unrecognized tax benefits of $7.3 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 $51.1 million, the timing of which is uncertain. Refer to Note 13 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, HELCO, KPLC and Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy). If any of these electric utilities fails to make payments under its PPAs with us, such failure would have a material adverse impact on our financial condition.

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Southern California Edison accounted for 17.5%, 27.7%, and 29.1% of our total revenues for the three years ended December 31, 2012, 2011, and 2010, respectively. Southern California Edison is also the power purchaser and revenue 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 15.3%, 13.0%, and 15.0% of our total revenues for the three years ended December 31, 2012, 2011, and 2010, respectively.

HELCO accounted for 9.4%, 10.6%, and 8.6% of our total revenues for the three years ended December 31, 2012, 2011, and 2010, respectively.

KPLC accounted for 7.9%, 8.0%, and 9.4% of our total revenues for the three years ended December 31, 2012, 2011, and 2010, respectively.

Government Grants and Tax Benefits

The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies. If we start construction of a new geothermal power plant in the U.S. by December 31, 2013, 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. If we fail to meet the start of construction deadline for such a project, then the 30% credit is reduced to 10%. In lieu of the 30% tax credit (if the project qualifies), we are permitted to claim a tax credit based on the power produced from a geothermal power plant. These production-based credits, which in 2012 were 2.2 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. The owner of the power plant may not claim both the 30% tax credit and the production-based tax credit. Under current tax rules, any unused tax credit has a one-year carry back and a twenty-year carry forward. If we claim the ITC, our “tax basis” in the plant that we can recover through depreciation must be reduced by half of the ITC. If we claim the PTC, there is no reduction in the tax basis for depreciation. Companies that placed qualifying renewable energy facilities in service during 2009, 2010 or 2011 or that began construction of qualifying renewable energy facilities during 2009, 2010 or 2011 and place them in service by December 31, 2013, may choose to apply for a cash grant from the U.S. Treasury in an amount equal to the ITC. Likewise, the tax basis for depreciation will be reduced by 50% of the cash grant received. Under the ARRA, the U.S. Treasury is instructed to pay the cash grant within 60 days of the application or the date on which the qualifying facility is placed in service.

Our subsidiary, 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 could 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 cannot exceed 25% for an additional five years until 2013 (see also below). These benefits are subject to certain conditions, including among other things, that all transactions between Ormat Systems and our affiliates are done on an arm’s length, and that the management of Ormat Systems will be located in, and the control will be conducted from Israel during the entire period of the tax benefits. A change in control needs to 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 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. 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 2014, and 12% in 2015 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

132

comply with the previous law during the transition period, with an 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 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. A company that makes this election will be required to make certain investments in its Benefited Enterprise by: (i) purchasing productive assets (other than buildings); (ii) investing in research and development in Israel; and/or (iii) paying salaries of new employees (other than directors and officers of the company) of the Benefited Enterprise. The number of new employees for these purposes will be determined in comparison to the number of employees employed by the Benefited Enterprise at the end of 2011. Such investment must be made over a period of five years commencing in the tax year in which the election is made. The amount of the required investment is determined pursuant to a formula setforth in the new legislation. A company that makes the election allowed under the new legislation cannot later undo its election. As of the date of this annual report Ormat Systems has not yet decided wether to make such election.

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.

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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			135
Consolidated Financial Statements as of December 31, 2012 and 2011 and for Each of the Three Years in the Period Ended December 31, 2012:
Consolidated Balance Sheets			136
Consolidated Statements of Operations and Comprehensive Income (Loss)			137
Consolidated Statements of Equity			138
Consolidated Statements of Cash Flows			139
Notes to Consolidated Financial Statements			140

134

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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 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, 2012, based on criteria established in Internal Control — Integrated Framework 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 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 11, 2013

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2012			2011
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	66,628		$	99,886
Marketable securities		—			18,521
Short-term bank deposit		3,010			—
Restricted cash, cash equivalents and marketable securities (all related to VIEs)		76,537			75,521
Receivables:
Trade		55,680			51,274
Related entity		373			287
Other		8,632			9,415
Due from Parent		311			260
Inventories		20,669			12,541
Costs and estimated earnings in excess of billings on uncompleted contracts		9,613			3,966
Deferred income taxes		637			1,842
Prepaid expenses and other		34,144			18,672

Total current assets		276,234			292,185
Unconsolidated investments		2,591			3,757
Deposits and other		36,187			22,194
Deferred income taxes		53,989			—
Deferred charges		35,351			40,236
Property, plant and equipment, net ($1,162,606 and $1,477,580 related to VIEs, respectively)		1,226,758			1,518,532
Construction-in-process ($253,775 and $271,859 related to VIEs, respectively)		396,141			370,551
Deferred financing and lease costs, net		31,371			28,482
Intangible assets, net		35,492			38,781

Total assets	$	2,094,114		$	2,314,718

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	98,001		$	105,112
Deferred income taxes		20,392			—
Billings in excess of costs and estimated earnings on uncompleted contracts		25,408			33,104
Current portion of long-term debt:
Limited and non-recourse (all related to VIEs):
Senior secured notes		28,231			21,464
Other loans		11,453			13,547
Full recourse		28,649			20,543

Total current liabilities		212,134			193,770
Long-term debt, net of current portion:
Limited and non-recourse (all related to VIEs):
Senior secured notes		312,926			341,157
Other loans		242,815			100,585
Full recourse:
Senior unsecured bonds (plus unamortized premium based upon 7% of $1,436)		250,904			250,042
Other loans		82,344			63,623
Revolving credit lines with banks		73,606			214,049
Liability associated with sale of tax benefits		51,126			69,269
Deferred lease income		66,398			68,955
Deferred income taxes		45,059			54,665
Liability for unrecognized tax benefits		7,280			5,875
Liabilities for severance pay		22,887			20,547
Asset retirement obligation		19,289			21,284
Other long-term liabilities		5,148			4,253

Total liabilities		1,391,916			1,408,074

Commitments and contingencies
Equity:
The Company’s stockholders’ equity:
Common stock, par value $0.001 per share; 200,000,000 shares authorized; 45,430,886 shares issued and outstanding as of December 31, 2012 and 2011		46			46
Additional paid-in capital		732,140			725,746
Retained earnings		(37,735	)		172,331
Accumulated other comprehensive income		651			595

		695,102			898,718
Noncontrolling interest		7,096			7,926

Total equity		702,198			906,644

Total liabilities and equity	$	2,094,114		$	2,314,718

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,
	2012			2011			2010
	(In thousands, except per share data)
Revenues:
Electricity	$	327,529		$	323,849		$	291,820
Product		186,879			113,160			81,410

Total revenues		514,408			437,009			373,230

Cost of revenues:
Electricity		244,634			244,037			242,326
Product		135,346			76,072			53,277

Total cost of revenues		379,980			320,109			295,603

Gross margin		134,428			116,900			77,627
Operating expenses:
Research and development expenses		6,108			8,801			10,120
Selling and marketing expenses		16,122			16,207			13,447
General and administrative expenses		28,267			27,885			27,442
Impairment charges		236,377			—			—
Write-off of unsuccessful exploration activities		2,639			—			3,050

Operating income (loss)		(155,085	)		64,007			23,568
Other income (expense):
Interest income		1,201			1,427			343
Interest expense, net		(64,069	)		(69,459	)		(40,473	)
Foreign currency translation and transaction gains (losses)		242			(1,350	)		1,557
Income attributable to sale of tax benefits		10,127			11,474			8,729
Gain on acquisition of controlling interest		—			—			36,928
Other non-operating income, net		590			671			130

Income (loss) from continuing operations, before income taxes and equity in income (losses) of investees		(206,994	)		6,770			30,782
Income tax benefit (provision)		3,500			(48,535	)		1,098
Equity in income (losses) of investees, net		(2,522	)		(959	)		998

Income (loss) from continuing operations		(206,016	)		(42,724	)		32,878
Discontinued operations:
Income from discontinued operations, net of related tax of $0		—			—			14
Gain on sale of a subsidiary in New Zealand, net of related tax of $2,000		—			—			4,336

Net income (loss)		(206,016	)		(42,724	)		37,228
Net loss (income) attributable to noncontrolling interest		(414	)		(332	)		90

Net income (loss) attributable to the Company’s stockholders	$	(206,430	)	$	(43,056	)	$	37,318

Comprehensive income (loss):
Net income (loss)		(206,016	)		(42,724	)		37,228
Other comprehensive income, net of related taxes:
Currency translation adjustment		—			—			43
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge		(190	)		(212	)		(234	)
Change in unrealized gains or losses on marketable securities available-for-sale		246			(237	)		(80	)

Comprehensive income (loss)		(205,960	)		(43,173	)		36,957
Comprehensive loss (income) attributable to noncontrolling interest		(414	)		(332	)		90

Comprehensive income (loss) attributable to the Company’s stockholders	$	(206,374	)	$	(43,505	)	$	37,047

Earnings (loss) per share attributable to the Company’s stockholders:
Basic:
Income (loss) from continuing operations	$	(4.54	)	$	(0.95	)	$	0.72
Discontinued operations		—			—			0.10

Net income (loss)	$	(4.54	)	$	(0.95	)	$	0.82

Diluted:
Income (loss) from continuing operations	$	(4.54	)	$	(0.95	)	$	0.71
Discontinued operations		—			—			0.10

Net income (loss)	$	(4.54	)	$	(0.95	)	$	0.82

Weighted average number of shares used in computation of earnings (loss) per share attributable to the Company’s stockholders:
Basic		45,431			45,431			45,431

Diluted		45,431			45,431			45,452

Dividend per share declared	$	0.08		$	0.13		$	0.27

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
	Common Stock				Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income			Total			Noncontrolling Interest			Total Equity
	Shares		Amount		Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income			Total			Noncontrolling Interest			Total Equity
	(In thousands, except per share data)
Balance at December 31, 2009		45,431		46		709,354		196,950			622			906,972			4,723			911,695
Stock-based compensation		—		—		7,377		—			—			7,377			—			7,377
Cumulative effect of adopting the guidance on evaluation of credit derivatives embedded in beneficial interests in securitized financial assets as of July 1, 2010 (net of related tax of $370)		—		—		—		(693	)		693			—			—			—
Increase in noncontrolling interest, due to acquisition		—		—		—		—			—			—			1,462			1,462
Cash dividend declared, $0.27 per share		—		—		—		(12,264	)		—			(12,264	)		—			(12,264	)
Net income (loss)		—		—		—		37,318			—			37,318			(90	)		37,228
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment		—		—		—		—			43			43			—			43
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $143)		—		—		—		—			(234	)		(234	)		—			(234	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $43)		—		—		—		—			(80	)		(80	)		—			(80	)

Balance at December 31, 2010		45,431		46		716,731		221,311			1,044			939,132			6,095			945,227
Stock-based compensation		—		—		6,672		—			—			6,672			—			6,672
Increase in noncontrolling interest due to sale of equity interest in OPC LLC		—		—		2,343		—			—			2,343			1,499			3,842
Cash dividend declared, $0.13 per share		—		—		—		(5,924	)		—			(5,924	)		—			(5,924	)
Net (loss) income		—		—		—		(43,056	)		—			(43,056	)		332			(42,724	)
Other comprehensive income (loss), net of related taxes:
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $130)		—		—		—		—			(212	)		(212	)		—			(212	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $0)		—		—		—		—			(237	)		(237	)		—			(237	)

Balance at December 31, 2011		45,431		46		725,746		172,331			595			898,718			7,926			906,644
Stock-based compensation		—		—		6,394		—			—			6,394			—			6,394
Cash paid to noncontrolling interest		—		—		—		—			—			—			(1,244	)		(1,244	)
Cash dividend declared, $0.08 per share		—		—		—		(3,636	)		—			(3,636	)		—			(3,636	)
Net (loss) income		—		—		—		(206,430	)		—			(206,430	)		414			(206,016	)
Other comprehensive income (loss), net of related taxes:
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $117)		—		—		—		—			(190	)		(190	)		—			(190	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $0)		—		—		—		—			246			246			—			246

Balance at December 31, 2012		45,431	$	46	$	732,140	$	(37,735	)	$	651		$	695,102		$	7,096		$	702,198

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,
	2012			2011			2010
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	(206,016	)	$	(42,724	)	$	37,228
Adjustments to reconcile net income or loss to net cash provided by operating activities:
Depreciation and amortization		102,340			96,398			86,761
Amortization of premium from senior unsecured bonds		(307	)		(256	)		—
Accretion of asset retirement obligation		1,701			1,593			1,249
Stock-based compensation		6,394			6,672			7,377
Amortization of deferred lease income		(2,685	)		(2,685	)		(2,685	)
Income attributable to sale of tax benefits, net of interest expense		(4,003	)		(4,315	)		(3,523	)
Equity in income (losses) of investees		442			959			(998	)
Impairment of auction rate securities		—			205			137
Loss on disposal of property, plant and equipment		—			—			1,245
Write-off of unconsolidated investment		2,114			—			—
Write-off of unsuccessful exploration activities		2,639			—			3,050
Impairment charge		236,377			—			—
Return on investment in unconsolidated investments		—			—			3,734
Loss (gain) on severance pay fund asset		(931	)		588			(1,889	)
Premium from issuance of senior unsecured bonds		—			1,957			—
Gain on sale of a subsidiary		—			—			(6,350	)
Gain on acquisition of controlling interest		—			—			(36,928	)
Deferred income tax provision (benefit)		(11,327	)		38,061			(10,139	)
Liability for unrecognized tax benefits		1,405			444			500
Deferred lease revenues		128			376			1,082
Changes in operating assets and liabilities, net of amounts acquired:
Receivables		(3,623	)		1,979			1,259
Costs and estimated earnings in excess of billings on uncompleted contracts		(5,647	)		2,180			8,894
Inventories		(8,128	)		(3	)		2,948
Prepaid expenses and other		(15,472	)		(3,743	)		(2,595	)
Deposits and other		(12,746	)		(710	)		(164	)
Accounts payable and accrued expenses		11,414			6,646			9,695
Due from/to related entities, net		(86	)		16			(89	)
Billings in excess of costs and estimated earnings on uncompleted contracts		(7,696	)		29,951			(198	)
Liabilities for severance pay		2,340			(159	)		2,610
Other long-term liabilities		895			(708	)		(540	)
Due from/to Parent		(51	)		12			(268	)

Net cash provided by operating activities		89,471			132,734			101,403

Cash flows from investing activities:
Return of investment in unconsolidated investments		—			—			3,516
Marketable securities, net		18,763			(17,534	)		—
Short-term deposit		(3,010	)		—			—
Net change in restricted cash, cash equivalents and marketable securities		(1,016	)		(50,614	)		17,536
Cash received from sale of a subsidiary		—			—			19,594
Capital expenditures		(233,020	)		(269,677	)		(283,313	)
Cash grant received		119,199			—			108,286
Investment in unconsolidated companies		(1,390	)		(472	)		(2,715	)
Cash paid for acquisition of controlling interest in a subsidiary, net of cash acquired		—			—			(64,517	)
Cash paid for investment in a joint venture		—			(200	)		(100	)
Intangible assets acquired		—			(1,786	)		(1,472	)
Decrease in severance pay fund asset, net of payments made to retired employees		(316	)		(719	)		(635	)

Net cash used in investing activities		(100,790	)		(341,002	)		(203,820	)

Cash flows from financing activities:
Proceeds from issuance of senior unsecured bonds		1,171			107,447			142,003
Proceeds from long-term loans, net of transaction costs		214,051			—			20,000
Proceeds from issuance of senior secured notes, net of transaction costs		—			141,108			—
Proceeds from the sale of limited liability company interest in OPC LLC, net of transaction costs		—			24,878			—
Proceeds from revolving credit lines with banks		2,953,535			891,583			1,159,869
Repayment of revolving credit lines with banks		(3,093,978	)		(867,000	)		(1,104,403	)
Repayments of long-term debt
Parent		—			—			(9,600	)
Other		(74,502	)		(50,130	)		(52,242	)
Cash paid to non-controlling interest		(15,383	)		(14,039	)		(3,136	)
Deferred debt issuance costs		(3,197	)		(2,584	)		(1,302	)
Cash dividends paid		(3,636	)		(5,924	)		(12,264	)

Net cash provided by (used in) financing activities		(21,939	)		225,339			138,925

Net change in cash and cash equivalents		(33,258	)		17,071			36,508
Cash and cash equivalents at beginning of year		99,886			82,815			46,307

Cash and cash equivalents at end of year	$	66,628		$	99,886		$	82,815

Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest, net of interest capitalized	$	40,398		$	33,274		$	34,587

Income taxes, net	$	11,570		$	13,575		$	7,570

Supplemental non-cash investing and financing activities:
Increase (decrease) in accounts payable related to purchases of property, plant and equipment	$	(18,813	)	$	13,117		$	507

Payable related to investment in joint venture	$	—		$	—		$	2,400

Increase (decrease) in asset retirement cost and asset retirement obligation	$	(3,696	)	$	(212	)	$	1,238

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”), a subsidiary of Ormat Industries Ltd. (the “Parent”), 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, Guatemala, and Nicaragua. 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 were in compliance with Qualifying Facility status requirements as of December 31, 2012.

Cash dividends

During the years ended December 31, 2012, 2011, and 2010, the Company’s Board of Directors declared, approved, and authorized the payment of cash dividends in the aggregate amount of $3.6 million ($0.08 per share), $5.9 million ($0.13 per share), and $12.3 million ($0.27 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. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Marketable securities

Marketable securities consist of debt securities. The Company determines the appropriate classification of all marketable securities as held-to-maturity, available-for-sale or trading at the time of the purchase and re-evaluates such classification at each balance sheet date. At December 31, 2012 and 2011, all of the Company’s investments in marketable securities were classified as available-for-sale securities and as a result, were reported at their fair value.

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, cash equivalents, and marketable securities. Funds that will be used to satisfy obligations due during the next twelve months are classified as current restricted cash, cash equivalents, and marketable securities, with the remainder classified as non-current restricted cash, cash equivalents and marketable securities (see Note 7). 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, marketable securities and accounts receivable.

The Company places its temporary cash investments and marketable securities with high credit quality financial institutions located in the U.S. and in foreign countries. At December 31, 2012 and 2011, the Company had deposits totaling $41,231,000 and $39,569,000, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account. At December 31, 2012 and 2011, the Company’s deposits in foreign countries of approximately $33,215,000 and $57,838,000, respectively, were not insured.

At December 31, 2012 and 2011, accounts receivable related to operations in foreign countries amounted to approximately $17,606,000 and $21,453,000, respectively. At December 31, 2012, and 2011, accounts receivable from the Company’s major customers that have generated 7.5% or more of its revenues (see Note 20) amounted to approximately 45% and 58%, respectively, of the Company’s accounts receivable.

Southern California Edison Company (“Southern California Edison”) accounted for 17.5%, 27.7%, and 29.1% of the Company’s total revenues for the years ended December 31, 2012, 2011, and 2010, respectively. Southern California Edison is also the power purchaser and revenue source for the Mammoth complex, which was accounted for separately under the equity method through August 1, 2010.

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 15.3%, 13.0%, and 15.0% of the Company’s total revenues for the years ended December 31, 2012, 2011, and 2010, respectively.

Hawaii Electric Light Company accounted for 9.4%, 10.6%, and 8.6% of the Company’s total revenues for the years ended December 31, 2012, 2011, and 2010, respectively.

Kenya Power and Lighting Co. Ltd. accounted for 7.9%, 8.0%, and 9.4% of the Company’s total revenues for the years ended December 31, 2012, 2011, and 2010, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company performs ongoing credit evaluations of its customers’ financial condition. 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 significant at December 31, 2012 and 2011.

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

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 25 to 30 years. The geothermal power plant in Zunil, Guatemala is to be fully depreciated over the term of the PPA, since the Company does not own the geothermal resource used by the plant. The geothermal power plant in Nicaragua is to be fully depreciated over the period that the plant is operated by the Company (see Note 8). The other assets are depreciated using the straight-line method over the following estimated useful lives of the assets:


Leasehold improvements			15-20 years
Machinery and equipment — manufacturing and drilling			10 years
Machinery and equipment — computers			3-5 years
Office equipment — furniture and fixtures			5-15 years
Office equipment — other			5-10 years
Automobiles			5-7 years

The cost and accumulated depreciation of items sold or retired are removed from the accounts. Any resulting gain or loss is recognized currently and is recorded in operating income.

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 $11,964,000, $11,709,000, and $9,493,000 for the years ended December 31, 2012, 2011, and 2010, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash Grants

From time to time, the Company is 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 records the cash grant as a reduction in the carrying value of the related plant and amortizes the grant as a reduction in depreciation expense over the plant’s estimated useful life.

For federal income tax purposes, the tax basis of the plant is reduced only by 50% of the cash grant. To account for the tax effect of the difference between the tax and book basis of the plant, the Company records a deferred tax asset with a corresponding decrease in the carrying value of the plant.

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, 2012, 2011, and 2010. 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.

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 either be converted to a full-size commercial well, used either for extraction or re-injection or geothermal fluids, or 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Grants received from the U.S. Department of Energy (“DOE”) are offset against the related exploration and development costs. Such grants amounted to $1,368,000, $6,194,000, and $1,116,000 for the years ended December 31, 2012, 2011, and 2010, 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 $20,209,000 and $16,533,000 at December 31, 2012 and 2011, respectively. Amortization expense for the years ended December 31, 2012, 2011, and 2010 amounted to $3,676,000, $3,567,000, and $3,042,000, respectively.

Deferred transaction costs relating to the Puna operating lease (see Note 12) in the amount of $4,172,000 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 $1,405,000 and $1,221,000 at December 31, 2012 and 2011, respectively. Amortization expense for each of the years ended December 31, 2012, 2011, and 2010 amounted to $184,000.

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.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 (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 except for the North Brawley and OREG 4 power plants described in Note 8, 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 currently 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 are subsequently reclassified into earnings when the hedged forecasted transaction affects earnings. Gains or losses on contracts that are not designated to qualify as a cash flow hedge are included currently in earnings.

Foreign currency translation

The U.S. dollar is the functional currency for substantially all of the Company’s consolidated operations and those of its equity affiliates. For those entities, all gains and losses from currency translations are included in results of operations. For the subsidiary in New Zealand that was sold in January 2010, and which was using a functional currency other than the U.S. dollar, the cumulative translation effects were included in “accumulated other comprehensive income (loss)” in the consolidated balance sheets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Comprehensive income (loss) reporting

Comprehensive income (loss) includes net income or loss plus other comprehensive income (loss), which for the Company consists of foreign currency translation adjustments, the non-credit portion of unrealized gain or loss on available-for-sale marketable securities and the mark-to-market gains or losses on derivative instruments designated as a cash flow hedge.

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, 2012, 2011, and 2010.

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 $660,000, $1,143,000, and $704,000 for the years ended December 31, 2012, 2011, and 2010, respectively.

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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). The Company uses the simplified method in developing an estimate of the expected term of “plain vanilla” stock-based awards.

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 valuation allowance has been established to reduce the Company’s deferred tax assets to the amount that is expected to be realized in the future. 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.

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,
	2012		2011		2010
	(In thousands)
Weighted average number of shares used in computation of basic earnings (loss) per share		45,431		45,431		45,431
Add:
Additional shares from the assumed exercise of employee stock awards		—		—		21

Weighted average number of shares used in computation of diluted earnings (loss) per share		45,431		45,431		45,452

In the years ended December 31, 2012 and 2011, the employee stock options were anti-dilutive because of the Company’s net loss, and therefore, they have been excluded from the diluted earnings (loss) per share calculation.

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 5,479,852, 4,337,475, and 2,676,712, respectively, for the years ended December 31, 2012, 2011, and 2010.

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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, 2012

Fair Value Measurement

In May 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance regarding fair value measurements and disclosures. Required disclosures were expanded under the new guidance, particularly for fair value measurements that are categorized within Level 3 of the fair value hierarchy, for which quantitative information about the unobservable inputs, the valuation processes used by the entity, and the sensitivity of the measurement to the unobservable inputs are required. In addition, entities are required to disclose the categorization by level of the fair value hierarchy for items that are not measured at fair value in the balance sheet but for which the fair value is required to be disclosed. The adoption of this guidance by the Company on January 1, 2012 did not have a material impact on the Company’s consolidated financial statements. See Note 7 for these and other fair value related disclosures.

Presentation of Comprehensive Income in the Financial Statements

In June 2011, the FASB issued authoritative guidance intended to increase the prominence of items reported in other comprehensive income. The guidance eliminates the option to present components of other comprehensive income as part of the statement of changes in equity and requires that the total of comprehensive income, the components of net income, and the components of other comprehensive income be presented in a single continuous statement of comprehensive income or in two separate but consecutive statements. The guidance also required presentation of adjustments for items that are reclassified from other comprehensive income in the statement where the components of net income and the components of other comprehensive income are presented, which was indefinitely deferred by the FASB in December 2011. The guidance (other than the portion regarding the presentation of reclassification adjustments which, as noted above, has been deferred indefinitely) became effective on January 1, 2012. The adoption of this guidance by the Company on January 1, 2012 did not have a material impact on the Company’s consolidated financial statements.

New accounting pronouncement effective in future periods

Disclosures about Offsetting Assets and Liabilities

In December 2011, the FASB issued accounting guidance to amend the existing disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures, as well as to improve comparability of balance sheets prepared under GAAP and those prepared under IFRS. In January 2013, the FASB issued additional guidance on the scope of these disclosures. The revised disclosure guidance applies to derivative instruments and securities borrowing and lending transactions that are subject to an enforceable master netting

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arrangement or similar agreement. The revised disclosure guidance is effective on a retrospective basis for interim and annual periods beginning January 1, 2013. As this guidance provides for additional disclosure requirements only, the adoption of this guidance is not expected to have an impact on the Company’s results of operations, financial position or cash flows.

Amounts Reclassified Out of Accumulated Other Comprehensive Income

In February 2013, the FASB updated accounting guidance to add new disclosure requirements for items reclassified out of accumulated other comprehensive income. The update does not change the current requirements for reporting net income or other comprehensive income in financial statements. However, the amendments require an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional detail about those amounts. The amendments are required to be applied prospectively for interim and annual reporting periods beginning January 1, 2013. As this guidance provides for additional disclosure requirements only, the adoption of this guidance is not expected to have an impact on the Company’s results of operations, financial position or cash flows.

NOTE 2 — MAMMOTH COMPLEX ACQUISITION

On August 2, 2010, the Company acquired the remaining 50% interest in Mammoth-Pacific, L.P. (“Mammoth Pacific”), which owns the Mammoth complex located near the city of Mammoth, California, for a purchase price of $72.5 million in cash. The Company acquired the remaining interest in Mammoth Pacific to increase its geothermal power plant operations in the United States.

Prior to the acquisition, the Company had a 50% interest in Mammoth Pacific that was accounted for under the equity method of accounting. Following the acquisition, the Company became the sole owner of the Mammoth complex, as well as the sole owner of rights to over 10,000 acres of undeveloped federal lands.

As a result of the acquisition of the remaining 50% interest in Mammoth Pacific, the financial statements of Mammoth Pacific have been consolidated with the Company’s financial statements effective August 2, 2010. The acquisition-date fair value of the previously held 50% equity interest was $64.9 million, which takes into account a “control premium” of $7.6 million. In the year ended December 31, 2010, the Company recognized a pre-tax gain of $36.9 million, which is equal to the difference between the acquisition-date fair value of the previously held 50% equity interest in Mammoth Pacific and the acquisition-date carrying value of such investment. The gain is included in “gain on acquisition of controlling interest” in the consolidated statements of operations and comprehensive income (loss).

The values of the assets acquired and liabilities assumed at the acquisition date are based on management’s estimates using the methodology and assumptions described below.

Valuation methodology and assumptions

In estimating the fair value for the assets acquired, the Company primarily relied on the “Income Approach”. After reviewing several geothermal transactions, the Company concluded that those transactions

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were not sufficiently comparable to the assets acquired in this transaction. The Company also considered the “Cost Approach” as a reasonableness check to compare to the “Income Approach” value, but did not rely on it as a final indicator of the value.

The “Income Approach” is based on the premise that the value of an asset is equal to the present value of the cash flows that the assets are expected to generate. To estimate the fair value of the existing and replacement tangible and intangible assets as well as the development project at the Mammoth Pacific site, a discounted cash flow (“DCF”) analysis was utilized whereby the cash flows expected to be generated by the acquired assets were discounted to their present value equivalent using the rate of return that reflects the relative risk of each asset, as well as the time value of money. This return, known as the weighted average cost of capital (“WACC”), is an overall rate based upon the individual rates of return for invested capital (equity and interest-bearing debt), and was calculated by weighting the acquired return on interest-bearing debt and common equity capital in proportion to their estimated percentage in the expected capital structure. The estimates for the WACC, which ranged from 9.5% to 14.0%, developed in the valuation are for independent power producers and geothermal power producers.

The following table summarizes the fair value of the assets acquired and liabilities assumed at the acquisition date:


	(dollars in thousands)
Assets:
Cash and cash equivalents	$	7,983
Trade receivables		3,239
Prepaid expenses and other		254
Deposits and other		622
Property, plant and equipment, net (including construction-in-process)		129,764

Total identifiable assets acquired		141,862

Liabilities:
Current liabilities — accounts payable and accrued expenses		(1,072	)
Asset retirement obligation		(3,342	)

Total identifiable liabilities assumed		(4,414	)

Total net assets acquired	$	137,448

The acquired property, plant and equipment will be depreciated over their estimated useful lives.

The revenues of the Mammoth complex and the net loss of the Mammoth complex were $7,567,000 and $645,000, respectively, for the period from August 2, 2010 to December 31, 2010.

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The following unaudited consolidated pro forma financial information for the year ended December 31, 2010, assumes the Mammoth Pacific acquisition occurred as of January 1, 2010, after giving effect to certain adjustments, including the depreciation based on the adjustments to the fair market value of the property, plant and equipment acquired, and related income tax effects. The pro forma results have been prepared for comparative purposes only and are not necessarily indicative of the results of operations that may occur in the future or that would have occurred had the acquisition of Mammoth Pacific been effected on the date indicated.


	(Dollars in thousands, except per share data)
Revenues	$	384,706

Loss from continuing operations		8,954

Net income		13,304
Net loss attributable to noncontrolling interest		90

Net income attributable to the Company’s stockholders	$	13,394

Earnings per share attributable to the Company’s stockholders — basic and diluted:
Income from continuing operations	$	0.20
Income from discontinued operations		0.10

Net income	$	0.30

NOTE 3 — INVENTORIES

Inventories consist of the following:


	December 31,
	2012		2011
	(Dollars in thousands)
Raw materials and purchased parts for assembly	$	9,775	$	6,058
Self-manufactured assembly parts and finished products		10,894		6,483

Total	$	20,669	$	12,541

NOTE 4 — COST AND ESTIMATED EARNINGS ON UNCOMPLETED CONTRACTS

Cost and estimated earnings on uncompleted contracts consist of the following:


	December 31,
	2012			2011
	(Dollars in thousands)
Costs and estimated earnings incurred on uncompleted contracts	$	192,948		$	69,427
Less billings to date		(208,743	)		(98,565	)

Total	$	(15,795	)	$	(29,138	)

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These amounts are included in the consolidated balance sheets under the following captions:


	December 31,
	2012			2011
	(Dollars in thousands)
Costs and estimated earnings in excess of billings on uncompleted contracts	$	9,613		$	3,966
Billings in excess of costs and estimated earnings on uncompleted contracts		(25,408	)		(33,104	)

Total	$	(15,795	)	$	(29,138	)

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.

NOTE 5 — UNCONSOLIDATED INVESTMENTS

Unconsolidated investments, mainly in power plants, consist of the following:


	December 31,
	2012		2011
	(Dollars in thousands)
Sarulla	$	2,591	$	2,215
Watts & More Ltd.		—		1,542

	$	2,591	$	3,757

The Sarulla Project

The Company is a 12.75% member of a consortium which is in the process of developing a geothermal power project in Indonesia with expected generating capacity of approximately 340 megawatts (“MW”). The 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 with PT Pertamina Geothermal Energy. The project will be constructed in three phases over a period of five years, with each phase utilizing the Company’s 110 MW to 120 MW combined cycle geothermal 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 consortium is in the process of negotiating certain contractual amendments for facilitation of project financing and for signing the resulting amended energy sales contract, and intends to proceed with the project after those amendments have become effective.

The Company’s share in the results of operations of the Sarulla project was not significant for each of the years presented in these consolidated financial statements.

Watts & More Ltd.

In December 2012, the Company acquired additional shares in Watts & More Ltd. (“W&M”) and as a result holds 60% of W&M’s outstanding ordinary shares and W&M was consolidated as of December 31, 2012.

The Company’s investment in W&M prior to its consolidation was not significant for each of the years presented in these consolidated financial statements.

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The Mammoth Complex

Prior to August 2, 2010, the Company had a 50% interest in Mammoth Pacific, which owns the Mammoth complex. The Company’s 50% ownership interest in Mammoth Pacific was accounted for under the equity method of accounting as the Company had the ability to exercise significant influence, but not control, over Mammoth Pacific. On August 2, 2010, the Company acquired the remaining 50% interest in Mammoth Pacific (see Note 2).

The unaudited condensed results of Mammoth Pacific for the period from January 1, 2010 to August 1, 2010 are summarized below:


	(Dollars in thousands)
Condensed statements of operations:
Revenues	$	11,484
Gross margin		2,670
Net income		2,528
Company’s equity in income of Mammoth:
50% of Mammoth net income	$	1,264
Plus amortization of basis difference		345

		1,609
Less income taxes		(611	)

Total	$	998

NOTE 6 — VARIABLE INTEREST ENTITIES

Effective January 1, 2010, the Company adopted accounting and disclosure guidance for variable interest entities (“VIEs”). Among other accounting and disclosure requirements, the guidance requires the primary beneficiary of a VIE to be identified as the party that both (i) has the power to direct the activities of a VIE that most significantly impact its economic performance; and (ii) has an obligation to absorb losses or a right to receive benefits that could potentially be significant to the VIE. The adoption of this accounting guidance did not result in the Company consolidating any additional VIEs or deconsolidating any VIEs.

The Company evaluated all transactions and relationships with VIEs to determine whether the Company is the primary beneficiary of the entities in accordance with the guidance. The Company’s overall methodology for evaluating transactions and relationships under the VIE 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

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•

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; (ii) wholly owned subsidiaries with PPAs; and (iii) less than majority-owned subsidiaries.

Agreement for joint development, construction, ownership and operation of one or more geothermal power plants in Oregon

On October 29, 2010, the Company entered into an agreement to jointly develop, construct, finance, own and operate one or more geothermal power plants in the Crump Geothermal Area located in Lake County, Oregon (the “Crump Project”). Under the terms of the agreement, the other joint owner, Nevada Geothermal Power Inc., contributed all of its rights, titles and interest in the Crump Project, consisting mainly of geothermal rights, to the newly formed entity. The Company paid $0.1 million and will pay an additional $2.4 million over a three-year period to the other joint owner for its ownership interest in the Crump Project and related rights. The Company has a 50% voting interest and will have equal representation with the other joint owner on the governing board. During the development stage of the Crump Project, the Company has the obligation to fund the first $15.0 million on behalf of the Crump Project. All other funding requirements will be required jointly by each owner. If the other joint owner is unable to obtain the necessary capital to fund its share of the Crump Project, the Company will provide financing directly to the joint owner in an aggregate amount of up to $15.0 million. In addition, the Company will be responsible for leading the development of the Crump Project and once operational, will be considered the operator of the facility. At any time during the development or construction of the Crump Project, the Company may terminate its involvement in the Crump Project, whereby the Company

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would transfer its 50% ownership interest to the other joint owner, at no cost to the other joint owner. If this occurs, the Company will have no obligation to make any additional payments to the other joint owner.

The Company concluded that the entity is a VIE primarily because the entity does not have sufficient equity at risk. Through the Company’s equity ownership and other variable interest, the Company determined that it is the primary beneficiary of the Crump Project and therefore will consolidate the assets, liabilities and operations. In making the determination to consolidate, the Company considered the activities that most significantly impact the project’s economic performance, which party has the power to direct those activities, and whether the obligation to absorb the losses or the right to receive the benefits could potentially be significant to the Crump Project. The Company determined that the activities that most significantly impact the economic performance of the Crump Project currently include the development of the project. As the Company is the managing member and is primarily responsible during the development phase and further, since the Company’s obligations and benefits would be significant to the Crump Project, the Company determined that it is the primary beneficiary.

The Company has incurred $11.1 million in development costs of the Crump Project, as of December 31, 2012, which are presented in the Company’s consolidated balance sheet in “construction-in-process”. No amounts related to this transaction have been included in the statement of operations and comprehensive income (loss) during the years ended December 31, 2011 and 2010. In addition, the assets related to the Crump Project can only be used to settle the obligations related to the Crump Project.

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, 2012 and 2011:


	December 31, 2012
	Project Debt		PPAs		Less than Majority- owned Subsidiary
	(Dollars in thousands)
Assets:
Restricted cash, cash equivalents and marketable securities	$	76,537	$	—	$	—
Other current assets		73,135		8,766		—
Property, plant and equipment, net		966,433		196,173		—
Construction-in-process		248,890		4,885		11,121
Other long-term assets		57,337		273		—

Total assets	$	1,422,332	$	210,097	$	11,121

Liabilities:
Accounts payable and accrued expenses	$	25,477	$	5,393	$	—
Billings in excess of costs and estimated earnings on uncompleted contracts		1,718		—
Long-term debt		595,425		—		—
Other long-term liabilities		81,070		8,386		—

Total liabilities	$	703,690	$	13,779	$	—

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	December 31, 2011
	Project Debt		PPAs		Less Than Majority- Owned Subsidiary
	(Dollars in thousands)
Assets:
Restricted cash, cash equivalents and marketable securities	$	75,521	$	—	$	—
Other current assets		78,013		12,725		—
Property, plant and equipment, net		1,019,082		428,498		—
Construction-in-process		236,101		24,585		11,173
Other long-term assets		57,386		272		—

Total assets	$	1,466,103	$	466,080	$	11,173

Liabilities:
Accounts payable and accrued expenses	$	13,621	$	4,590	$	—
Long-term debt		476,753		—		—
Other long-term liabilities		84,619		7,998		—

Total liabilities	$	574,993	$	12,588	$	—

NOTE 7 — 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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The following table sets forth certain fair value information at December 31, 2012 and 2011 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.


	Cost or Amortized Cost at December 31, 2012		Fair Value at December 31, 2012
	Cost or Amortized Cost at December 31, 2012		Total		Level 1		Level 2		Level 3
	(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	54,298	$	54,298	$	54,298	$	—	$	—
Marketable Securities		—		—		—		—		—
Derivatives:
Put options on oil price⁽¹⁾		—		1,842		—		1,842		—
Swap transaction on oil price⁽²⁾		—		336		—		336		—
Swap transaction on natural gas price⁽³⁾		—		2,804		—		2,804		—
Currency forward contracts⁽⁴⁾		—		1,675		—		1,675		—

	$	54,298	$	60,955	$	54,298	$	6,657	$	—


	Cost or Amortized Cost at December 31, 2011		Fair Value at December 31, 2011
	Cost or Amortized Cost at December 31, 2011		Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	61,649	$	61,649		$	61,649	$	—		$	—
Marketable Securities		18,284		18,521			18,521		—			—
Liabilities:
Current liabilities:
Derivatives:
Currency forward contracts⁽⁵⁾		—		(890	)		—		(890	)		—

	$	79,933	$	79,820		$	80,170	$	(890	)	$	—

⁽¹⁾

This amount relates to derivatives which represent swap contract on oil prices, valued primarily based on observable inputs, including forward and spot prices for related commodity indices, and are included within “prepaid expenses and other” in the consolidated balance sheet with the corresponding gain or loss being recognized within “electricity revenues” in the consolidated statement of operations and comprehensive income (loss).

⁽²⁾

⁽³⁾

This amount relates to derivatives which represent swap contract on natural gas prices, valued primarily based on observable inputs, including forward and spot prices for related commodity indices, and are included within “prepaid expenses and other” in the consolidated balance sheet with the corresponding gain or loss being recognized within “electricity revenues” in the consolidated statement of operations and comprehensive income (loss).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

⁽⁴⁾

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” in the consolidated balance sheet with the corresponding gain or loss being recognized within “foreign currency translation and transaction gains (losses)” in the consolidated statement of operations and comprehensive income (loss).

⁽⁵⁾

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 “accounts payable and accrued expenses” in the consolidated balance sheet with the corresponding gain or loss being recognized within “foreign currency translation and transaction gains (losses)” in the consolidated statement of operations and comprehensive income (loss).

The Company’s financial assets measured at fair value (including restricted cash accounts) at December 31, 2012 and 2011 include investments in debt instruments (which are included in marketable securities), money market funds (which are included in cash equivalents) and short-term bank deposits. 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.

As of December 31, 2010, all of the Company’s auction rate securities were associated with failed auctions. Such securities had par values totaling $4.5 million, all of which had been in a loss position since the fourth quarter of 2007. The Company’s auction rate securities at December 31, 2010, were valued using Level 3 inputs. Historically, the carrying value of auction rate securities approximated fair value due to the frequent resetting of the interest rates. While the Company continued to earn interest on these investments at the contractual rates, the estimated market value of these auction rate securities no longer approximated par value. Due to the lack of observable market quotes on the Company’s illiquid auction rate securities, the Company utilized valuation models that relied exclusively on Level 3 inputs including, among other things: (i) the underlying structure of each security; (ii) the present value of future principal and interest payments discounted at rates considered to reflect the uncertainty of current market conditions; (iii) consideration of the probabilities of default, auction failure, or repurchase at par for each period; (iv) assessments of counterparty credit quality; (v) estimates of the recovery rates in the event of default for each security; and (vi) overall capital market liquidity. These estimated fair values were subject to uncertainties that were difficult to predict. Therefore, such auction rate securities were classified as Level 3 in the fair value hierarchy.

In the year ended December 31, 2011, the Company identified a buyer outside of the auction process, and sold the balance of the auction rate securities for consideration of $2,822,000.

The table below sets forth a summary of the changes in the fair value of the Company’s financial assets classified as Level 3 (i.e., illiquid auction rate securities) for each of the years ended December 31, 2011 and 2010:


	Year Ended December 31,
	2011			2010
	(Dollars in thousands)
Balance at beginning of period	$	3,027		$	3,164
Sale of auction rate securities		(2,822	)		—
Total unrealized gains (losses):
Included in net income		(205	)		(137	)

Balance at end of year	$	—		$	3,027

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Effective July 1, 2010, the Company adopted an accounting standards update that amends and clarifies the guidance on how entities should evaluate credit derivatives embedded in beneficial interests in securitized financial assets. The updated guidance eliminates the scope exception for bifurcation of embedded credit derivatives in interests in securitized financial assets unless they are created solely by subordination of one beneficial interest to another. The auction rate securities held by the Company are considered securitized financial assets and therefore fall under the guideline in the abovementioned accounting standards update. The Company elected the fair value option for its auction rate securities as permitted by the update. Upon adoption of this accounting standards update, the Company reclassified $693,000 (net of income taxes of $377,000) to retained earnings with an offset to other comprehensive income. Effective with the adoption of this new guidance, all changes in the fair value of auction rate securities are recognized in earnings.

In April 2012, the Company entered into a NYMEX Heating Oil swap contract (85%) and an ICE Brent swap contract (15%) for notional volume of 241,250 BBL with a bank effective from May 1, 2012 until March 31, 2013 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 these contracts because both swaps had a high correlation with the avoided costs (which are the incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others) that HELCO uses to calculate the energy rate. The contracts did not have up-front costs. Under the terms of these contracts, the Company will make floating rate payments to the bank and receive fixed rate payments from the bank on each settlement date ($130.50 per BBL in respect of NYMEX Heating Oil and $115.50 per BBL in respect of ICE Brent). The swap contracts have monthly settlements whereby the difference between the fixed price and the monthly average market price will be settled on a cash basis.

In May 2012, the Company entered into a European put transaction with a bank effective from July 1, 2012, pursuant to which the Company purchased a natural gas put option for 4.4 million MMbtus that settled against Natural Gas — California SoCal — NGI (“NGI”) on December 31, 2012. The Company entered into this transaction in order to reduce its exposure to NGI below $3.08 per MMbtu under its PPAs with Southern California Edison. The transaction was settled on December 31, 2012 for $1.2 million.

In July 2012, the Company entered into another European put transaction with the same bank for settlement effective from August 1, 2012, pursuant to which the Company purchased a natural gas put option for 0.7 million MMbtus that settled against NGI on December 31, 2012. The Company entered into this transaction in order to reduce its exposure to NGI below $3.19 per MMbtu under its PPAs with Southern California Edison. The transaction was settled on December 31, 2012 for $0.1 million.

On September 27, 2012, the Company entered into European put transactions with two banks effective from January 1, 2013 until December 31, 2013, pursuant to which the Company purchased NYMEX Heating Oil put options for notional volume of 191,250 BBL, and ICE Brent put options for notional volume of 33,750 BBL. The Company entered into these transactions to reduce its 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 these transactions because both transactions had a high correlation with the avoided costs that HELCO uses to calculate the energy rate. The Company paid up-front premiums in the total amount of approximately $2.6 million that were recorded on September 27, 2012 as current assets and are marked to market on each balance sheet date. Under these transactions, the Company will receive from the banks on each settlement date the difference between the strike price of $126.63 per BBL in respect of NYMEX Heating Oil and $106.80 in respect of ICE Brent and the respective monthly average market price of the relevant commodity. If the strike price is lower than the monthly average market price, no payment will be made.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On October 11, 2012, the Company entered into NGI swap contracts for notional volume of approximately 8.9 million MMbtus with a bank for settlement effective from January 1, 2013 until December 31, 2013, in order to reduce its exposure to NGI below $4.00 per MMbtu under its PPAs with Southern California Edison. The contracts did not have up-front costs. Under the terms of these contracts, the Company will make floating rate payments to the bank and receive fixed rate payments from the bank on each settlement date. The swap contracts have monthly settlements whereby the difference between the fixed price of $4.00 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, 2013 to December 1, 2013) will be settled on a cash basis.

These transactions have not been designated as hedge transactions and are marked to market with the corresponding gains or losses recognized within “electricity revenues” in the consolidated statements of operations and comprehensive income (loss). The Company recognized a net gain from these transactions of $2.3 million in the year ended December 31, 2012.

There were no transfers of assets or liabilities between Level 1 and Level 2 during the year ended December 31, 2012.

The fair value of the Company’s long-term debt approximates its carrying amount, except for the following:


	Fair Value				Carrying Amount
	December 31,				December 31,
	2012		2011		2012		2011
	(Dollars in millions)				(Dollars in millions)
Olkaria III Loan – DEG	$	48.8	$	79.2	$	47.4	$	77.4
Amatitlan Loan		38.9		37.2		34.3		36.8
Senior Secured Notes:
Ormat Funding Corp. (“OFC”)		105.0		114.8		114.1		125.0
OrCal Geothermal Inc. (“OrCal”)		77.3		84.4		76.5		85.9
OFC 2 LLC (“OFC 2”)		131.2		131.0		150.5		151.7
Senior Unsecured Bonds		273.2		252.8		250.9		248.3
Loan from institutional investors		27.7		34.2		27.0		34.2

The fair value of OFC Senior Secured Notes is determined using observable market prices as these securities are traded. The fair value of the other 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, deposits, and other long-term debt approximates fair value.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the fair value of financial instruments as of December 31, 2012:


	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Amatitlan loan	$	—	$	—	$	38.9	$	38.9
Senior Secured Notes:
OFC		—		105.0		—		105.0
OrCal		—		—		77.3		77.3
OFC 2		—		—		131.2		131.2
Senior unsecured bonds		—		—		273.2		273.2
Loan from institutional investors		—		—		27.7		27.7
Olkaria III Loan—DEG		—		—		48.8		48.8
Other long-term debt		—		36.7		—		36.7
Revolving credit lines with banks		—		73.6		—		73.6
Deposits		21.7		—		—		21.7

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

The North Brawley geothermal power plant was tested for impairment as of December 31, 2012 due to the low output and higher than expected operating costs. The plant was placed in service under its PPA with Southern California Edison in 2010. However, management found that the North Brawley geothermal field was significantly more difficult to operate than other fields of the Company and the power plant was unable to reach its design capacity of 50 MW and instead, operated at capacities between 20 MW and 33 MW. This generation level was achieved only after significant additional capital expenditures and higher than anticipated operating costs.

In order to improve the economics of the plant, the Company approached Southern California Edison to discuss various contractual alternatives to the PPA and, in early 2012, it reached a written understanding to engage in discussions with third parties about purchasing the power at better rates. However, in a letter dated January 14, 2013, Southern California Edison informed the Company that it is no longer interested in pursuing alternatives to the current PPA, thus retracting its permission to the Company to explore a replacement PPA with higher electricity prices.

As a result of Southern California Edison’s notification and the rates under the existing PPA, coupled with a further understanding of the cost and probability of success of additional well field work which has been accumulated in recent months, the Company has concluded that it will not be economical to continue to invest the substantial capital required to increase the generating capacity of the power plant. Accordingly, the Company decided to operate the plant at the current capacity level of approximately 27 MW and refrain from additional capital investment to expand the capacity.

Based on these indicators, the power plant was tested for recoverability by estimating its future cash flows taking into consideration rates to be received under the PPA with Southern California Edison through the end of its term and expected market rates thereafter, possible penalties for underperformance during periods when the plant is expected to operate below the stated capacity in the PPA, projected capital expenditures and projected operating expenses over the life of the plant.

As a result, the North Brawley power plant was written down to its fair value of $32.0 million. The impairment loss of $229.1 million is presented in the consolidated statement of operations and comprehensive income (loss) under “Impairment Charges”.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In estimating the fair value for the power plant, the Company primarily relied on the “Income Approach”, using assumptions that the Company believes market participants would utilize in making such valuation. The “Income Approach” is based on the principle that the value of an asset is equal to the present value of the cash flows that the asset is expected to generate. To estimate the fair value of the power plant, a discounted cash flow (“DCF”) analysis was utilized whereby the cash flows expected to be generated by the power plant were discounted to their present value equivalent using the rate of return that reflects the relative risk of each asset, as well as the time value of money. This return, known as the weighted average cost of capital (“WACC”), an overall rate based upon the individual rates of return for invested capital (equity and interest-bearing debt), was calculated by weighting the acquired return on interest-bearing debt and common equity capital in proportion to their estimated percentage in the expected capital structure. The estimate for the WACC of 8% developed in the valuation is for independent power producers and geothermal power producers.

In addition to the WACC rate of 8%, other significant inputs of the future net cash flow estimates included in the valuation are generation output, average realized price, and operating costs. These future net cash flow estimates are classified as Level 3 within the fair value hierarchy. Below are the significant unobservable inputs for each year included in the valuation as of the year ended December 31, 2012.


(Dollars in thousands, except realized price)
	Valuation Technique		Amount or Range	Weighted Average
Generation output (MWh)		DCF	224,836	224,836
Average realized price ($/MWh)		DCF	$84.50 — $111.25	$92.31
Operating costs		DCF	$12,687 — $20,430	$16,163

OREG 4, a recovered energy generation power plant, was also tested for impairment in the third quarter of 2012 due to continued low run time of the compressor station that serves as it heat source, which resulted in low power generation and revenues. Based on these indicators, the power plant was tested for recoverability by estimating its future cash flows over the life of the plant.

As a result, the OREG 4 power plant was written down to its fair value of $3.6 million. The impairment loss of $7.3 million is presented in the consolidated statement of operations and comprehensive income (loss) under “Impairment Charges”.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(Dollars in thousands, except realized price)
	Valuation Technique		Amount or Range	Weighted Average
Generation output (MWh)		DCF	11,916 — 15,456	15,097
Average realized price ($/MWh)		DCF	$49.00 — $71.50	$60.36
Operating costs		DCF	$86 — $595	$400

The Jersey Valley geothermal power plant, which is under development, was tested for impairment in the current year due to the low output due to injection constraints. Based on these indicators the power plant was tested for recoverability by estimating its future cash flows taking into consideration the various outcomes from different generating capacities, rates to be received under the PPA through the end of its term and expected market rates thereafter, possible penalties for underperformance during periods when the plant is expected to operate below the stated capacity in the PPA, projected capital expenditures to complete development of the plant and projected operating expenses over the life of the plant. The Company applied a probability-weighted approach and considered alternative courses of action.

Using a probability-weighted approach, the estimated undiscounted cash flows exceed the carrying value of the plant ($65.5 million as of December 31, 2012) by approximately $31.2 million and therefore, no impairment was recognized. Estimated undiscounted cash flows are subject to significant uncertainties. If actual cash flows differ from our current estimates due to factors that include, among others, if the plant’s future generating capacity is less than approximately 10 MW, or if the capital expenditures required to complete development of the plant and/or future operating costs exceed the level of the Company’s current projections, a material impairment write-down may be required in the future.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 8 — PROPERTY, PLANT AND EQUIPMENT AND CONSTRUCTION-IN-PROCESS

Property, plant and equipment

Property, plant and equipment, net, consist of the following:


	December 31,
	2012			2011
	(Dollars in thousands)
Land owned by the Company where the geothermal resource is located	$	32,396		$	32,411
Leasehold improvements		1,339			1,325
Machinery and equipment		100,499			92,227
Office equipment		15,218			16,444
Automobiles		5,816			5,581
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		1,296,534			1,534,001
Foreign countries		312,412			281,896
Asset retirement cost		7,214			9,441

		1,771,428			1,973,326
Less accumulated depreciation		(544,670	)		(454,794	)

Property, plant and equipment, net	$	1,226,758		$	1,518,532

Depreciation expense for the years ended December 31, 2012, 2011, and 2010 amounted to $89,876,000, $89,600,000, and $80,669,000, respectively. Depreciation expense for the years ended December 31, 2012 and 2011 is net of the impact of the cash grant in the amount of $5,553,000 and $3,681,000, 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 $1,261,520,000 and $1,625,961,000 as of December 31, 2012 and 2011, respectively. These amounts as of December 31, 2012 and 2011 are net of cash grants in the amount of $117,320,000 and $103,222,000, respectively (net of accumulated depreciation of $1,872,000 and $5,063,000 as of December 31, 2012 and 2011, respectively). The cash grant amounts include the write-off of the North Brawley power plant. The write-off associated with this grant was $99,542,000 (net of accumulated depreciation of $8,744,000).

Impairment tests of the North Brawley, OREG 4 and Jersey Valley power plants were performed during the year ended December 31, 2012 resulting in impairment charges for the North Brawley and OREG 4 power plants (see Note 7).

Foreign Operations

The net book value of property, plant and equipment, including construction-in-process, located outside of the United States was approximately $361,379,000 and $263,121,000 as of December 31, 2012 and 2011, 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 $272,050,000 and $169,701,000 as of December 31, 2012 and 2011, respectively. The Company sells the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

electricity produced by the power plants to Kenya Power and Lighting Co. Ltd. (“KPLC”) under a 20-year PPA. The Company has incurred approximately $167,344,000 and $67,551,000 (included in construction-in-process) at December 31, 2012 and 2011, respectively, in connection with the construction of Phase III of the complex.

Pursuant to an agreement with Empresa Nicaraguense de Electricitdad (“ENEL”), a Nicaraguan power utility, the Company rehabilitated existing wells, drilled new wells, and is operating the geothermal facilities. The Company owns the plants for a fifteen-year period ending in 2014, at which time they will be transferred to ENEL at no cost. The net book value of the assets related to the plant and wells was $3,931,000 and $7,987,000 at December 31, 2012 and 2011, respectively.

The Company, through its wholly owned subsidiary, Orzunil I de Electricidad, Limitada (“Orzunil”), owns a power plant in Guatemala. The geothermal resources used by the power plant are owned by Instituto Nacional de Elecrification (“INDE”), a Guatemalan power utility, who granted the use of these resources to Orzunil for the period of the PPA. The net book value of the assets related to the power plant was $21,628,000 and $24,732,000 at December 31, 2012 and 2011, 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 $43,360,000 and $45,189,000 at December 31, 2012 and 2011, respectively.

Construction-in-process

Construction-in-process consists of the following:


	December 31,
	2012		2011
	(Dollars in thousands)
Projects under exploration and development:
Up-front bonus lease costs	$	33,985	$	36,832
Exploration and development costs		32,302		40,223
Interest capitalized		1,278		1,598

		67,565		78,653

Projects under construction:
Up-front bonus lease costs		29,160		31,179
Drilling and construction costs		283,873		246,878
Interest capitalized		15,543		13,841

		328,576		291,898

Total	$	396,141	$	370,551

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Projects under Exploration and Development
	Up-front Bonus Lease Costs			Exploration and Development Costs			Capitalized Interest			Total
	(Dollars in thousands)
Balance at December 31, 2009	$	15,867		$	17,698		$	52		$	33,617
Cost incurred during the year		17,733			21,483			158			39,374
Write off of unsuccessful exploration costs		—			(2,940	)		(110	)		(3,050	)
Reclassification of exploration and development projects to drilling and construction		—			(15,244	)		—			(15,244	)

Balance at December 31, 2010		33,600			20,997			100			54,697
Cost incurred during the year		3,232			19,226			1,498			23,956
Write off of unsuccessful exploration costs		—									—
Reclassification of exploration and development projects to drilling and construction		—			—			—			—

Balance at December 31, 2011		36,832			40,223			1,598			78,653
Cost incurred during the year		—			3,782			420			4,202
Write off of unsuccessful exploration costs		(1,160	)		(1,479	)		—			(2,639	)
Reclassification of exploration and development projects to drilling and construction		(1,687	)		(10,224	)		(740	)		(12,651	)

Balance at December 31, 2012	$	33,985		$	32,302		$	1,278		$	67,565


	Projects under Construction
	Up-front Bonus Lease Costs			Drilling and Construction Costs			Capitalized Interest			Total
	(Dollars in thousands)
Balance at December 31, 2009	$	3,179		$	442,218		$	39,581		$	484,978
Cost incurred during the year		28,000			249,072			9,335			286,407
Write off of unsuccessful exploration costs		—			—			—			—
Reclassification of exploration and development projects to drilling and construction		—			15,244			—			15,244
Reclassification of completed projects to property, plant and equipment		—			(529,566	)		(41,126	)		(570,692	)

Balance at December 31, 2010		31,179			176,968			7,790			215,937
Cost incurred during the year		—			242,066			10,207			252,273
Write off of unsuccessful exploration costs		—			—			—			—
Reclassification of exploration and development projects to drilling and construction		—			—			—			—
Reclassification of completed projects to property, plant and equipment		—			(172,156	)		(4,156	)		(176,312	)

Balance at December 31, 2011		31,179			246,878			13,841			291,898
Cost incurred during the year		—			216,894			11,541			228,435
Write off of unsuccessful exploration costs		—			—			—			—
Reclassification of exploration and development projects to drilling and construction		1,687			10,224			740			12,651
Reclassification of completed projects to property, plant and equipment		(3,706	)		(190,123	)		(10,579	)		(204,408	)

Balance at December 31, 2012	$	29,160		$	283,873		$	15,543		$	328,576

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 9 — INTANGIBLE ASSETS

Intangible assets consist mainly of the Company’s PPAs acquired in business combinations and amounted to $35,492,000 and $38,781,000, net of accumulated amortization of $28,654,000 and $25,365,000, as of December 31, 2012 and 2011, respectively. Amortization expense for the years ended December 31, 2012, 2011, and 2010 amounted to $3,289,000, $3,279,000, and $3,179,000, respectively.

Estimated future amortization expense for the intangible assets as of December 31, 2012 is as follows:


	(Dollars in thousands)
Year ending December 31:
2013	$	3,289
2014		3,289
2015		3,289
2016		3,289
2017		3,289
Thereafter		19,047

Total	$	35,492

NOTE 10 — ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses consist of the following:


	December 31,
	2012		2011
	(Dollars in thousands)
Trade payables	$	51,303	$	69,894
Salaries and other payroll costs		10,423		10,174
Customer advances		9,592		4,900
Accrued interest		9,110		9,273
Income tax payable		1,467		1,464
Property tax		4,399		3,323
Scheduling and transmission		594		1,059
Royalty		1,646		1,065
Other		9,467		3,960

Total	$	98,001	$	105,112

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 11 — LONG-TERM DEBT AND CREDIT AGREEMENTS

Long-term debt consists of notes payable under the following agreements:


	December 31,
	2012			2011
	(Dollars in thousands)
Limited and non-recourse agreements:
Loans:
Non-recourse:
Loan agreement with DEG (the Olkaria III power plant)	$	—		$	77,368
Loan agreement with TCW (the Amatitlan power plant)		34,268			36,764
Limited recourse:
Loan agreement with OPIC (the Olkaria III power plant)		220,000			—
Senior Secured Notes:
Non-recourse:
Ormat Funding Corp. (“OFC”)		114,136			125,022
OrCal Geothermal Inc. (“OrCal”)		76,548			85,860
Limited recourse:
OFC 2 LLC (“OFC 2”)		150,473			151,739

		595,426			476,753
Less current portion		(39,684	)		(35,011	)

Non-current portion	$	555,741		$	441,742

Full recourse agreements:
Senior unsecured bonds	$	250,904		$	250,042
Loans from institutional investors:		43,624			54,166
Loan agreement with DEG (the Olkaria III power plant)		47,369			—
Loan from a commercial bank		20,000			30,000
Revolving credit lines with banks		73,606			214,049

		435,503			548,257
Less current portion		(28,649	)		(20,543	)

Non-current portion	$	406,854		$	527,714

Loan Agreement with TCW (the Amatitlan Power Plant)

In May 2009, the Company’s wholly owned subsidiary, Ortitlan, entered into a note purchase agreement, in an aggregate principal amount of $42.0 million which refinanced its investment in the 20 MW Amatitlan geothermal power plant located in Amatitlan, Guatemala (the “Amatitlan Loan”). The Amatitlan Loan was provided by TCW Global Project Fund II, Ltd. (“TCW”). The Amatitlan Loan will mature on June 15, 2016, and is payable in 28 quarterly installments. The Amatitlan Loan bears interest at a rate of 9.83%.

There are various restrictive covenants under the Amatitlan Loan, which include: (i) a projected 12-month debt service coverage ratio (“DSCR”) of not less than 1.2; and (ii) a long-term debt to equity ratio not to exceed 4 (both of which are measured quarterly). If Ortitlan fails to comply with these financial ratios it will be prohibited from making distributions to its shareholders. In addition, subject to certain cure rights, such failure will constitute an event of default by Ortitlan. As of December 31, 2012, the projected 12-month DSCR was 1.58, and the debt to equity ratio was 2.51.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Debt service reserve

As required under the terms of the Amatitlan Loan, Ortitlan 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 Amatitlan Loan in the following three months, and a well field reserve account. This restricted cash account is classified as current in the consolidated balance sheets. As of December 31, 2012 and 2011, the balance of such account was and $3.8 million. In addition, as of December 31, 2012 and 2011, part of the required debt service reserve was backed by a letter of credit in the amount of $5.9 million for both years (see Note 23).

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 on November 9, 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 up to $180.0 million will be used to fund the construction and well field drilling for the expansion of the Olkaria III geothermal power complex to up to 84 MW (“Plant 2”). On November 9, 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 is a stand-by tranche in an aggregate principal amount of up to $45.0 million, and will be made available to OrPower 4 in the event it elects, in its discretion, to construct a further expansion of the Olkaria III complex of up to an additional 16 MW (“Plant 3”). Terms and conditions for Tranche III of the OPIC Loan will be agreed upon by OPIC and OrPower 4 in subsequent documentation.

The applicable Tranche interest rate will be determined at the time of the actual disbursement of loan proceeds based upon, and in connection with, the issuance of certificates of participation in the OPIC Loan. The payment of principal and interest on the certificates of participation is fully guaranteed by OPIC, and is backed by the full faith and credit of the U.S. government.

The final maturity of Tranche I and Tranche II is approximately 18 years.

OrPower 4 has the 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

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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 repayment of the remaining outstanding DEG Loan (see below) in the amount of approximately $51.3 million as of November 9, 2012, has been subordinated to the OPIC Loan.

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, 2012, the balance of the account was $18.9 million. In addition, as of December 31, 2012, part of the required debt service reserve was backed by a letter of credit in the amount of $8.0 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

On February 13, 2004, OFC, a wholly owned subsidiary, issued $190.0 million, 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, which have been included in deferred financing costs in the consolidated balance sheet. 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

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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. As of December 31, 2012 (the last measurement date of the covenants), the actual historical 12-month DSCR was 1.28.

In February 2013, the Company acquired from OFC noteholders OFC Senior Secured Notes with an outstanding aggregate principal amount of $12.8 million and will recognize a gain of $1.1 million in the first quarter of 2013.

OFC may redeem the OFC Senior Secured Notes, in whole or in part, at any time, at a 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 December 31, 2012 and 2011, the balance of such account was $2.9 million and $1.8 million, respectively. In addition, as of each of December 31, 2012 and 2011, part of the required debt service reserve was backed by a letter of credit in the amount of $10.6 million (see Note 23).

OrCal Senior Secured Notes

On December 8, 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- and BB as of December 31, 2012 and March 8, 2013, respectively, 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. As of December 31, 2012 (the last measurement date of the covenants), the actual historical 12-month DSCR was 1.36.

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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, 2012 and 2011, the balance of such account was $2.6 million and $0, respectively. In addition, as of December 31, 2012 and 2011, part of the required debt service reserve was backed by a letter of credit in the amount of $4.9 million and $4.8 million, respectively (see Note 23).

OFC 2 Senior Secured Notes

On September 23, 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’s 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 include 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.

Issuance of the Series B Notes is dependent on the Jersey Valley power plant reaching certain operational targets in addition to the other conditions precedent noted above. If issued, the aggregate principal of the Series B Notes will not exceed $28.0 million, and such proceeds would be used to finance a portion of the construction costs of Phase I of the Jersey Valley power plant.

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The OFC 2 Issuers have sole discretion regarding whether to commence construction of Phase II of any of the Jersey Valley, McGinness Hills and Tuscarora power plants. If a facility Phase II is undertaken for any of the power plants, the OFC 2 Issuers may issue Phase II tranches of Notes, comprised of one or more of Series C Notes, Series D Notes, Series E Notes and Series F Notes, to finance a portion of the construction costs of such Phase II of any facility. The aggregate principal amount of all Phase II Notes may not exceed $170.0 million. The aggregate principal amount of each series of Notes comprising a Phase II tranche will be determined by the OFC 2 Issuers in their sole discretion provided that certain financial ratios are satisfied pursuant to the terms of the Note Purchase Agreement and subject to the aggregate limit noted above.

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 quarterly DSCR requirement of at least 1.2 (on a blended basis for all of the OFC 2 power plants) and 1.5 on a pro forma basis (giving effect to the distributions). As of December 31, 2012 (the last measurement date of the covenants), the actual DSCR for the fourth quarter of 2012 was 2.69 and the pro-forma 12-month DSCR was 2.13.

The Company provided a guarantee in connection with the issuance of the Series A Notes, and will provide a guarantee in connection with the issuance of each other Series of OFC 2 Senior Secured Notes, which will be available to be drawn upon if certain trigger events occur. 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, 2012, part of the required debt service reserve was backed by a letter of credit in the amount of $10.4 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, 2012, the balance of such account was $44.0 million, and in addition OFC 2 funded $10.0 million in a letter of credit issued that is required to be maintained at all times until this reserve reduces to zero.

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(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. Certain other reserves are required in the event OFC 2 elects to commence construction of Phase II of any facility and fund such construction with any Series of Notes (other than Series A and Series B Notes).

Senior Unsecured Bonds

On August 3, 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 is repayable in a single bullet payment upon the final maturity of the Bonds on August 1, 2017. The Bonds bear interest at a fixed rate of 7%, payable semi-annually. In February 2011, the Company accepted subscription for an aggregate principal amount of approximately $108.0 million of additional senior unsecured bonds (the “Additional Bonds”) under two addendums to the trust instrument. The terms and conditions of the Additional Bonds are identical to the original Bonds. The Additional Bonds were issued at a premium which reflects an effective fixed interest of 6.75%.

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 matures on July 16, 2015, is payable in 12 semi-annual installments, which commenced on January 16, 2010, and bears interest of 6.5%.

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%.

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 matures on November 16, 2016, is payable in ten semi-annual installments, which commenced on May 16, 2012, and bears interest of 5.75%.

Loan Agreement 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%.

On October 31, 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

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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.

Loan from a commercial bank

On November 4, 2009, the Company entered into a 5-year loan agreement of $50.0 million with a commercial bank. The bank loan matures on November 10, 2014 and is payable in 10 semi-annual installments, which commenced on May 10, 2010, and bears interest at 6-month LIBOR plus 3.25%.

Revolving credit lines with commercial banks

As of December 31, 2012, the Company has credit agreements with six commercial banks for an aggregate amount of $445.8 million (including $50.0 million from Union Bank, N.A. (“Union Bank”)), 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 $265.0 million; and (ii) the issuance of one or more letters of credit in the amount of up to $180.8 million. The credit agreements mature between June 2013 and December 2014. 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, 2012, loans in the total amount of $73.6 million were outstanding, and letters of credit with an aggregate stated amount of $183.8 million were issued and outstanding under such credit agreements. The $73.6 million in loans are for terms of three months or less and bear interest at an annual weighted average rate of 2.71%.

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 million and in no event less than 30% 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 7; and (iii) dividend distribution not to exceed 35% of net income for that year. As of December 31, 2012: (i) total equity was $702.2 million and the actual equity to total assets ratio was 34.2%, and (ii) the 12-month debt, net of cash, cash equivalents, marketable securities and short-term bank deposits to Adjusted EBITDA ratio was 4.73. During the year ended December 31, 2012, the Company distributed interim dividends in an aggregate amount of $3.6 million. Although the Company reported a net loss for the year, under the credit agreements, the loan agreements, and the trust instrument governing the

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bonds the Company can distribute interim dividends on the basis of its estimate of its net income for the year. Since the Company incurred a loss for the year ended December 31, 2012, an adjustment of $3.6 million will be made in the next fiscal year in which the Company distributes a dividend. 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.

Credit agreement with Union Bank

On February 7, 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 and the aggregate amount available under the credit agreement was increased from $39.0 million to $50.0 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, 2012: (i) the actual 12-month debt to EBITDA ratio was 2.38; (ii) the 12-month DSCR was 3.26; and (iii) the distribution leverage ratio was 1.19. 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, 2012, letters of credit in the aggregate amount of $42.5 million remain issued and outstanding under this credit agreement with Union Bank.

Future minimum payments

Future minimum payments under long-term obligations, excluding revolving credit lines with commercial banks, as of December 31, 2012 are as follows:


	(Dollars in thousands)
Year ending December 31:
2013	$	68,333
2014		77,266
2015		70,850
2016		86,188
2017		308,938
Thereafter		345,748

Total	$	957,323

NOTE 12 — 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”).

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Pursuant to a 31-year head lease (the “Head Lease”), PGV leased 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, 2012 and 2011 amounted to $39.6 million and $42.4 million, net of accumulated depreciation of $22.8 million and $20.0 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, 2012, are as follows:


	(Dollars in thousands)
Year ending December 31:
2013	$	8,062
2014		8,647
2015		8,222
2016		8,374
2017		8,747
Thereafter		21,876

Total	$	63,928

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 $4.4 million and $3.9 million as of December 31, 2012 and 2011, 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 the Company’s wholly owned subsidiary, 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, 2012 and 2011, the balance of such account was $0.

NOTE 13 — OPC TRANSACTION

In June 2007, the Company’s wholly owned subsidiary Ormat Nevada entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. (Morgan Stanley Geothermal LLC

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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 not known with certainty and is determined by the operating results of OPC. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

NOTE 14 — 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,
	2012			2011
	(Dollars in thousands)
Balance at beginning of year	$	21,284		$	19,903
Changes in price estimates		(3,696	)		(1,071	)
Liabilities incurred		—			859
Accretion expense		1,701			1,593

Balance at end of year	$	19,289		$	21,284

During the year ended December 31, 2012, the Company decreased the aggregate carrying amount of its asset retirement obligation by $3,696,000 due to decreased costs associated with demolition and abandonment of property, plant and equipment.

During the year ended December 31, 2011, the Company decreased the aggregate carrying amount of its asset retirement obligation by $1,071,000 due to changes in useful life and price estimates.

NOTE 15 — 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, 2012, the total future compensation cost related to unvested stock-based awards that are expected to vest is $8,016,000, which amount will be recognized over a weighted average period of 1.3 years.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

During the years ended December 31, 2012, 2011 and 2010, the Company recorded compensation related to stock-based awards as follows:


	Year Ended December 31,
	2012		2011		2010
	(in thousands, except per share data)
Cost of revenues	$	4,225	$	4,325	$	4,403
Selling and marketing expenses		542		600		780
General and administrative expenses		1,611		1,747		2,195

Total stock-based compensation expense		6,378		6,672		7,378
Tax effect on stock-based compensation expense		797		834		924

Net effect of stock-based compensation expense	$	5,581	$	5,838	$	6,454

Effect of stock-based compensation expense on earnings (loss) per share	$	0.12	$	0.13	$	0.14

During the third quarter of 2012, the Company evaluated the trends in the stock-based award forfeiture rate and determined that the actual rate is 6.4%. This represents a decrease of 1.1% from the estimate made a year earlier in the third quarter of 2011. As a result of the reduction of the estimated forfeiture rate, the stock based compensation expense increased by an immaterial amount.

Valuation assumptions

The fair value of each grant of stock-based awards is estimated using the Black-Scholes valuation model and the assumptions noted in the following table. The Company’s expected term represents the period that the Company’s stock-based awards are 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. Since the Company does not have any traded stock-based award and was listed for trading on the New York Stock Exchange beginning in November 2004, the Company’s expected volatility was calculated based on the Company’s historical volatility and for the period of time prior to the Company’s listing, the historical volatility of the Parent. There is a high correlation between the stock behavior of the Company and its Parent. The dividend yield forecast is expected to be 20% of the Company’s yearly net profit, which is equivalent to a 0.0% yearly weighted average dividend rate in the year ended December 31, 2012. 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,
	2012			2011			2010
For stock options issued by the Company:
Risk-free interest rates		1.0	%		2.2	%		2.5	%
Expected lives (in years)		5.0			5.1			5.1
Dividend yield		0.81	%		0.80	%		0.72	%
Expected volatility		47.2	%		46.4	%		47.6	%
Forfeiture rate		6.4	%		7.5	%		13.0	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.


	Year Ended December 31,
	2012					2011					2010
	Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price
Outstanding at beginning of year		2,934		$	32.40		2,335		$	34.35		1,745		$	36.08
Granted, at fair value:
Stock Options		75			19.01		30			19.10		37			28.39
SARs*		602			20.13		622			25.65		592			29.95
Forfeited		(48	)		28.92		(53	)		31.69		(39	)		38.96

Outstanding at end of year		3,563			30.09		2,934			32.40		2,335			34.35

Options and SARs exercisable at end of year		1,592			36.61		1,086			37.46		621			37.65

Weighted-average fair value of options and SARs granted during the year				$	7.25				$	9.69				$	12.51

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

*	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, 2012, 3,925,000 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, 2012 (shares in thousands):


	Options Outstanding						Options Exercisable
Exercise Price	Number of Shares Outstanding		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value		Number of Shares Exercisable		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value
					(Dollars in thousands)						(Dollars in thousands)
$15.00		32		1.8		$136		32		1.8		$136
18.56		45		6.8		32		—		—		—
19.10		30		5.8		5		30		5.8		5
19.69		30		6.6		—		—		—		—
20.10		8		1.8		—		8		1.8		—
20.13		594		6.3		—		—		—		—
25.65		598		5.3		—		—		—		—
25.74		23		2.8		—		23		2.8		—
26.84		552		3.2		—		276		3.2		—
28.19		30		4.8		—		30		4.8		—
29.21		8		4.3		—		8		4.3		—
29.95		567		4.3		—		139		4.3		—
34.13		225		3.3		—		225		3.3		—
37.90		15		.8		—		15		.8		—
38.50		23		3.8		—		23		3.8		—
38.85		8		1.2		—		8		1.2		—
42.08		340		1.3		—		340		1.3		—
45.78		412		2.3		—		412		2.3		—
52.98		23		1.8		—		23		1.8		—

		3,563		4.0		$173		1,592		2.6		$141

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes information about stock-based awards outstanding at December 31, 2011 (shares in thousands):


	Options Outstanding						Options Exercisable
Exercise Price	Number of Shares Outstanding		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value		Number of Shares Exercisable		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value
					(Dollars in thousands)						(Dollars in thousands)
15.00		33		2.8	$	100		33		2.8	$	100
19.10		30		6.8		—		—		—		—
20.10		8		2.8		—		8		2.8		—
25.65		612		6.3		—		—		—		—
25.74		22		3.8		—		22		3.8		—
26.84		559		4.2		—		140		4.2		—
28.19		30		5.8		—		30		5.8		—
29.21		8		5.3		—		8		5.3		—
29.95		578		5.3		—		—		—		—
34.13		227		4.3		—		227		4.3		—
37.90		15		1.8		—		15		1.8		—
38.50		22		4.8		—		22		4.8		—
38.85		8		2.2		—		8		2.2		—
42.08		343		2.3		—		343		2.3		—
45.78		417		3.3		—		208		3.3		—
52.98		22		2.8		—		22		2.8		—

		2,934		4.5	$	100		1,086		3.3	$	100

The aggregate intrinsic value in the above tables represents the total pretax intrinsic value, based on the Company’s stock price of $19.28 and $18.03 as of December 31, 2012 and 2011, 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, 2012 and 2011 was 61,726 and 32,901, respectively.

No options were exercised during the years ended December 31, 2012, 2011, or 2010.

NOTE 16 — 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, Nicaragua, 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 2014 to 2034. 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 Nicaragua and 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 on 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 on 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 minimum lease revenues under PPAs which contain a lease element as of December 31, 2012 were as follows:


	(Dollars in thousands)
Year ending December 31:
2013	$	68,261
2014		68,319
2015		68,829
2016		62,078
2017		61,173
Thereafter		401,107

Total	$	729,767

The total minimum future lease revenues do not include contingent lease revenues that may be received under such PPAs that were concluded to contain a lease element. Such contingent lease revenue is based on the amount of time that the power plants are available to generate electricity in excess of stipulated minimums and the amount of electrical energy delivered at a designated delivery point.

NOTE 17 — DISCONTINUED OPERATIONS

In January 2010, a former shareholder of Geothermal Development Limited (“GDL”) who is the owner of an 8 MW power plant in New Zealand exercised a call option to purchase from the Company its shares in GDL for approximately $2.8 million. In addition, the Company received $17.7 million to repay the loan a subsidiary of the Company provided to GDL to build the plant. The Company did not exercise its right of first refusal and, therefore, the Company transferred its shares in GDL to the former shareholder after the former shareholder paid all of GDL’s obligations to the Company. As a result, the Company recorded a pre-tax gain of approximately $6.3 million in the year ended December 31, 2010 ($4.3 million after-tax).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The net assets of GDL on January 1, 2010 were as follows:


	(Dollars in thousands)
Cash and cash equivalents	$	871
Accounts receivables		434
Prepaid expenses and other		184
Property, plant and equipment		16,293
Accounts payables and accrued liabilities		(164	)
Other comprehensive income — translation adjustments		(156	)

Net assets	$	17,462

The operations and gain on the sale of GDL have been included in discontinued operations in the consolidated statements of operations and comprehensive income for all periods prior to the sale of GDL in January 2010. Basic and diluted earnings per share related to the $4.3 million after-tax gain on sale of GDL was $0.10 in the year ended December 31, 2010.

NOTE 18 — INTEREST EXPENSE, NET

The components of interest expense are as follows:


	Year Ended December 31,
	2012			2011			2010
	(Dollars in thousands)
Parent	$	—		$	—		$	310
Interest related to sale of tax benefits		6,827			7,837			5,429
Loss on interest rate lock transactions*		—			16,380			—
Other		69,206			56,951			44,227
Less — amount capitalized		(11,964	)		(11,709	)		(9,493	)

	$	64,069		$	69,459		$	40,473

*	The interest rate lock transactions are related to the OFC 2 Secured Notes and were not accounted for as a hedge (see Note 11).

NOTE 19 — INCOME TAXES

Income from continuing operations, before income taxes and equity in income (losses) of investees consisted of:


	Year Ended December 31,
	2012			2011			2010
	(Dollars in thousands)
U.S.	$	(283,242	)	$	(32,797	)	$	(3,715	)
Non-U.S. (foreign)		76,248		$	39,567		$	34,497

	$	(206,994	)	$	6,770		$	30,782

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The components of income tax provision (benefit) are as follows:


	Year Ended December 31,
	2012			2011			2010
	(Dollars in thousands)
Current:
State	$	(768	)	$	135		$	115
Foreign		8,595			10,339			10,926

	$	7,827		$	10,474		$	11,041

Deferred:
Federal		(23,903	)		38,566			(15,863	)
State		(44	)		(2,099	)		1,062
Foreign		12,620			1,594			2,662

		(11,327	)		38,061			(12,139	)

	$	(3,500	)	$	48,535		$	(1,098	)

The significant components of the deferred income tax expense (benefit) are as follows:


	Year Ended December 31,
	2012			2011			2010
	(Dollars in thousands)
Deferred tax expense (exclusive of the effect of other components listed below)	$	23,802		$	4,045		$	16,047
Write-off of power plants		(90,720	)		—			—
Usage (benefit) of operating loss carryforwards — U.S.		26,907			(35,575	)		(45,540	)
Change in valuation allowance		10,286			61,500			433
Change in foreign income tax		8,257			5,041			9,008
Change in lease transaction		1,170			1,027			769
Change in tax monetization transaction		5,353			(4,975	)		8,690
Change in intangible drilling costs		14,133			18,592			12,497
Benefit of production tax credits and alternative minimum tax credits		(10,515	)		(11,594	)		(14,043	)

Total	$	(11,327	)	$	38,061		$	(12,139	)

The difference between the U.S. federal statutory tax rate and the Company’s effective tax rate are as follows:


	Year Ended December 31,
	2012			2011			2010
U.S. federal statutory tax rate		35.0	%		35.0	%		35.0	%
Valuation allowance		(5.0	)		908.5			—
State income tax, net of federal benefit		4.1			(22.9	)		3.2
Effect of foreign income tax, net		2.7			(28.3	)		4.5
Production tax credits		5.1			(171.3	)		(45.7	)
Dividends from foreign subsidiaries		(40.2	)		—			—
Depletion		0.3			(12.0	)		—
Other, net		(0.3	)		7.9			(0.7	)

Effective tax rate		1.7	%		716.9	%		(3.7	)%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The net deferred tax assets and liabilities consist of the following:


	December 31,
	2012			2011
	(Dollars in thousands)
Deferred tax assets (liabilities):
Net foreign deferred taxes, primarily depreciation	$	(43,531	)	$	(35,274	)
Depreciation		44,701			(82,847	)
Intangible drilling costs		(66,881	)		(52,748	)
Net operating loss carryforward — U.S.		103,771			130,678
Dividends from foreign subsidiaries		(20,995	)		—
Tax monetization transaction		(26,470	)		(21,117	)
Lease transaction		3,410			4,582
Investment tax credits		1,971			1,971
Production tax credits		68,954			59,849
Alternative minimum tax credit		1,410			—
Stock options amortization		3,072			2,934
Accrued liabilities and other		653			649

		70,065			8,677
Less — valuation allowance		(80,890	)		(61,500	)

Total	$	(10,825	)	$	(52,823	)

The following table presents a reconciliation of the beginning and ending valuation allowance:


	Year Ended December 31,
	2012		2011		2010
	(Dollars in thousands)
Balance at beginning of the year	$	61,500	$	433	$	—
Additions to deferred income tax expense		19,390		61,067		433

Balance at end of the year	$	80,890	$	61,500	$	433

At December 31, 2012, the Company had U.S. federal net operating loss (“NOL”) carryforwards of approximately $267.6 million and state NOL carryforwards of approximately $193.4 million, net of valuation allowance of $129.7 million, available to reduce future taxable income, which expire between 2021 and 2032 for federal NOLs and between 2013 and 2032 for state NOLs. The investment tax credits (“ITCs”) in the amount of $2.0 million at December 31, 2012 are available for a 20-year period and expire between 2022 and 2024. The PTCs in the amount of $69.0 million at December 31, 2012 are available for a 20-year period and expire between 2026 and 2032.

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. The most significant factor considered in the ability of the Company to realize these deferred tax assets was the Company’s U.S. profitability over the past three years. Based on this profitability, a valuation allowance in the amount of $80.9 million and $61.5 million was recorded against the U.S. deferred tax assets as of December 31, 2012 and 2011, respectively as, at this point in time, it is more likely than not that the deferred tax assets will not be realized. If sufficient evidence of the Company’s ability to generate taxable income is established in the future, the Company may be required to reduce this valuation allowance, resulting in income tax benefits in its consolidated statement of operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the deferred taxes on the balance sheets as of the dates indicated:


	December 31
	2012			2011
	(Dollars in thousands)
Current deferred tax assets	$	637		$	1,842
Current deferred tax liabilities		(20,392	)		—
Non-current deferred tax assets		53,989			—
Non-current deferred tax liabilities		(45,059	)		(54,665	)

	$	(10,825	)	$	(52,823	)

The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $100.2 million at December 31, 2012. 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 distribution of $250 million in the form of a cash and loan from Ormat Holding Corporation and Ormat Systems, respectively, to the Company does not represent a change in the Company’s indefinite reinvestment position. The Company has not recognized deferred tax liabilities for outside basis differences (including undistributed earnings) relating to its foreign subsidiaries because such amounts have been indefinitely reinvested.

Uncertain tax positions

The liability for unrecognized tax benefits of $7.3 million and $5.9 million at December 31, 2012 and 2011, respectively, would impact the Company’s effective tax rate, if recognized. 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 the beginning and ending amounts of unrecognized tax benefits is as follows:


	Year Ended December 31,
	2012		2011			2010
	(Dollars in thousands)
Balance at beginning of year	$	5,875	$	5,431		$	4,931
Additions based on tax positions taken in prior years		1,381		1,207			823
Additions based on tax positions taken in the current year		25		612			260
Reduction based on tax positions taken in prior years		—		(1,375	)		(583	)

Balance at end of year	$	7,281	$	5,875		$	5,431

The Company and its U.S. subsidiaries file consolidated income tax returns for federal and state purposes. As of December 31, 2012, 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 2000-2012 and by local state jurisdictions for the years 2002-2012.

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The Company’s foreign subsidiaries remain open to examination by the local income tax authorities in the following countries for the years indicated:


Israel			2009 — 2012
Nicaragua			2009 — 2012
Kenya			2000 — 2012
Guatemala			2008 — 2012
Philippines			2008 — 2012
New Zealand			2008 — 2012

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. 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, 2014 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 2012 was 2.2 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 put into service by December 31, 2013. 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 2009, 2010 or 2011 and place them in service by December 31, 2013, 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, 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.

On June 7, 2007 and April 17, 2008, a wholly-owned subsidiary, Ormat Nevada, concluded transactions to monetize PTCs and other favorable tax attributes (see Note 13).

Income taxes related to foreign operations

Guatemala — The enacted tax rate is 31%. 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, 2012, 2011, and 2010 is $4.4 million, $4.4 million, and $3.2 million, respectively ($0.10, $0.10, and $0.07 per share of common stock, respectively).

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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 2010, 24% in 2011, and 25% in 2012 and thereafter (see also below). 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 (see also below). 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 2014, and 12% in 2015 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 legislation on such income and distribute a dividend from such income without being required to pay additional corporate tax with respect to such income. A company that makes this election will be required to make certain investments in its Benefited Enterprise by: (i) purchasing productive assets (other than buildings); (ii) investing in research and development in Israel; and/or (iii) paying salaries of new employees (other than directors and officers of the company) of the Benefited Enterprise. The number of new employees for these purposes will be determined in comparison to the number of employees employed by the Benefited Enterprise at the end of 2011. Such investment must be made over a period of five years commencing in the tax year in which the election is made. The amount of the required investment is determined pursuant to a formula set forth in the new legislation. A company that makes the election allowed under the new legislation cannot later undo from its election. As of the date of this annual report Ormat Systems has not yet decided whether to make such election.

Other significant foreign countries — The Company’s operations in Nicaragua and Kenya are taxed at the rates of 25% and 37.5%, respectively. The Company’s operations in New Zealand are taxed at the rate of 30% in 2010, and 28% in 2011 and 2012.

NOTE 20 — BUSINESS SEGMENTS

The Company has two reporting segments: 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 — (Continued)

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, 2012:
Net revenues from external customers	$	327,529		$	186,879	$	514,408
Intersegment revenues		—			48,315		48,315
Depreciation and amortization expense		98,783			3,557		102,340
Operating income (loss)		(185,364	)		30,279		(155,085	)
Segment assets at period end *		1,997,081			97,033		2,094,114
Expenditures for long-lived assets		228,289			4,731		233,020
* Including unconsolidated investments		2,591			—		2,591
Year Ended December 31, 2011:
Net revenues from external customers	$	323,849		$	113,160	$	437,009
Intersegment revenues		—			80,712		80,712
Depreciation and amortization expense		93,328			3,070		96,398
Operating income (loss)		45,138			18,869		64,007
Segment assets at period end *		2,222,836			91,882		2,314,718
Expenditures for long-lived assets		266,258			3,419		269,677
* Including unconsolidated investments		2,215			1,542		3,757
Year Ended December 31, 2010:
Net revenues from external customers	$	291,820		$	81,410	$	373,230
Intersegment revenues		—			70,275		70,275
Depreciation and amortization expense		84,276			2,485		86,761
Operating income (loss)		12,782			10,786		23,568
Segment assets at period end *		1,954,778			88,550		2,043,328
Expenditures for long-lived assets		280,228			3,223		283,451
* Including unconsolidated investments		2,244			2,000		4,244

Reconciling information between reportable segments and the Company’s consolidated totals is shown in the following table:


	Year Ended December 31,
	2012			2011			2010
	(Dollars in thousands)
Revenues:
Total segment revenues	$	514,408		$	437,009		$	373,230
Intersegment revenues		48,315			80,712			70,275
Elimination of intersegment revenues		(48,315	)		(80,712	)		(70,275	)

Total consolidated revenues	$	514,408		$	437,009		$	373,230

Operating income:
Operating income (loss)	$	(155,085	)	$	64,007		$	23,568
Interest income		1,201			1,427			343
Interest expense, net		(64,069	)		(69,459	)		(40,473	)
Foreign currency translation and transaction gains (losses)		242			(1,350	)		1,557
Income attributable to sale of equity interest		10,127			11,474			8,729
Gain on acquisition of controlling interest		—			—			36,928
Other non-operating income (expense), net		590			671			130

Total consolidated income (loss) before income taxes and equity in income of investees	$	(206,994	)	$	6,770		$	30,782

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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,
	2012		2011		2010
	(Dollars in thousands)
Revenues from external customers attributable to:⁽¹⁾
North America	$	271,845	$	254,265	$	241,732
Pacific Rim		109,177		32,174		6,878
Latin America		40,574		38,930		57,853
Africa		40,885		36,307		35,225
Far East		2,075		13,363		1,964
Europe		49,852		61,970		29,578

Consolidated total	$	514,408	$	437,009	$	373,230

⁽¹⁾	Revenues as reported in the geographic area in which they originate.


	Year Ended December 31,
	2012		2011		2010
	(Dollars in thousands)
Long-lived assets (primarily power plants and related assets) located in:
North America	$	1,332,762	$	1,686,088	$	1,536,583
Latin America		67,536		81,472		89,980
Africa		274,395		174,854		115,245
Europe		14,859		13,932		13,584
Pacific Rim and Far East		210		—		—

Consolidated total	$	1,689,762	$	1,956,346	$	1,755,392

The following table presents revenues from major customers:


	Year Ended December 31,
	2012				2011				2010
	Revenues		%		Revenues		%		Revenues		%
	(Dollars in thousands)				(Dollars in thousands)				(Dollars in thousands)
Southern California Edison:⁽¹⁾	$	90,239		17.5	$	121,049		27.7	$	108,481		29.1
Hawaii Electric Light Company⁽¹⁾		48,606		9.4		46,432		10.6		32,194		8.6
Sierra Pacific Power Company and Nevada Power Company⁽¹⁾⁽²⁾		78,631		15.3		56,778		13.0		55,877		15.0
Mighty River Power Limited⁽³⁾		99,617		19.4		19,956		4.6		—		—
Central American Bank for Economic
Integration (Las Pailas Project)⁽³⁾		—		—		—		—		21,365		5.7

⁽¹⁾	Revenues reported in Electricity Segment.

⁽²⁾	Subsidiaries of NV Energy, Inc.

⁽³⁾	Revenues reported in Products Segment.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 21 — TRANSACTIONS WITH RELATED ENTITIES

Transactions between the Company and related entities, other than those disclosed elsewhere in these financial statements, are summarized below:



	Year Ended December 31,
	2012		2011		2010
	(Dollars in thousands)
Property rental fee expense paid to the Parent	$	1,762	$	1,718	$	1,680

Interest expense on note payable to the Parent	$	—	$	—	$	310

Corporate financial, administrative, executive services, and research and development services provided to the Parent	$	146	$	143	$	139

Services rendered by an indirect shareholder of the Parent	$	51	$	54	$	116

The current asset due from the Parent at December 31, 2012 and 2011 in the amount of $311,000 and $260,000, respectively, represents the net obligation resulting from ongoing operations and transactions with the Parent and is payable from available cash flow. Interest is 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 is accrued and paid to the Parent annually.

Corporate and administrative services agreement with the Parent

Ormat Systems and the Parent have agreements whereby Ormat Systems will provide 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 has 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 is 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 will expire on the same day as the abovementioned lease agreement entered into in July 2004. Pursuant to the additional lease agreement, Ormat Systems pays 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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. Contributions made by the Company are matched up to a maximum of 2% of the employee’s annual salary. The Company’s contributions to the Plan were $507,000, $483,000, and $451,000 for the years ended December 31, 2012, 2011, and 2010, 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 obligations as if they 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 $19,940,000 and $18,693,000 at December 31, 2012 and 2011, 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, 2012, 2011, and 2010 were $2,320,000, $2,323,000, and $1,676,000, respectively, which are net of income (including loss) amounting to $930,000, ($522,000), and $1,889,000, respectively, generated from the regular deposits and amounts accrued in severance funds

The Company expects the severance pay contributions in 2013 to be approximately $2.7 million.

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:
2013	$	5,495
2014		591
2015		229
2016		1,319
2017		2,166
2018-2022		9,438

	$	19,238

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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 $12,048,000, $10,138,000, and $8,690,000 for the years ended December 31, 2012, 2011, and 2010, 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 $217.8 million at December 31, 2012. 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, 2012, total obligations related to such supplier agreements were approximately $93.6 million (out of which approximately $42.5 million relate to construction-in-process). All such obligations are payable in 2013.

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, 2012, 2011, and 2010. 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, 2012 and 2011, amounted to $1.5 million and $1.4 million, respectively, of which approximately $0.5 million increases based on the LIBOR rate, as defined above.

Contingencies

Securities Class Actions

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class action lawsuits were filed in the United States District Court for the District of Nevada on March 9, 2010, March 18, 2010 and April 7, 2010. These complaints asserted claims against the Company and certain directors and officers for alleged violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (the “Exchange Act”). One complaint also asserted claims for alleged violations of Sections 11, 12(a)(2) and 15 of the Securities Act of 1933, as amended (the “Securities Act”). All three complaints alleged claims on behalf of a putative class of purchasers of the Company’s common stock between May 6, 2008 or May 7, 2008 and February 23, 2010 or February 24, 2010. These three lawsuits were consolidated by the Court in an order issued on June 3, 2010, and the Court appointed three of the Company’s stockholders to serve as lead plaintiffs.

Lead plaintiffs filed a consolidated amended class action complaint (“CAC”) on July 9, 2010 that asserted claims under Sections 10(b) and 20(a) of the Exchange Act on behalf of a putative class of purchasers of the Company’s common stock between May 7, 2008 and February 24, 2010. The CAC alleged that certain of the Company’s public statements were false and misleading for failing to account properly for the Company’s exploration and development costs based on the Company’s announcement on February 24, 2010 that it was going to restate certain of its financial results to change its method of accounting for exploration and development costs in certain respects. The CAC also alleged that certain of the Company’s statements concerning the North Brawley project were false and misleading. The CAC sought compensatory damages, expenses, and such further relief as the Court may deem proper.

Stockholder Derivative Cases

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2010. All four lawsuits assert claims brought derivatively on behalf of the Company against certain of its directors and officers for alleged breach of fiduciary duty and other claims, including waste of corporate assets and unjust enrichment.

The Company believes the allegations in these purported derivative actions are without merit and, as part of the settlement, continues to deny any liability or wrongdoing.

Other

On December 24, 2012, Laborers’ International Union of North America Local Union No. 783 (“LiUNA”), an organized labor union, filed a petition in Mono County Superior Court, naming Mono County and the Company as defendant and real party in interest, respectively. The petitioners brought this action to challenge the November 13, 2012 decision of the Mono County Board of Supervisors in adopting Resolutions No. 12-78, denying Petitioners’ administrative appeal of the Planning Commission’s approval of Conditional Use Permit (“CUP”), adoption of findings under the California Environmental Quality Act (“CEQA”) and adoption of the final environmental impact report (“EIR”) for the Mammoth Pacific I replacement project. The petition asks the court to set aside the approval of the CUP and adoption of the EIR and cause a new EIR to be prepared and circulated.

On January 4, 2012, the California Unions for Reliable Energy (“CURE”) filed a petition in Alameda Superior Court, naming the California Energy Commission (“CEC”) and the Company as defendant and real

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party in interest, respectively. The petition asks the court to order the CEC to vacate its decision which denied, with prejudice, the complaint filed by CURE against the Company with the CEC. The CURE complaint alleged that the Company’s North Brawley Project and East Brawley Project both exceed the CEC’s 50 MW jurisdictional threshold and therefore are subject to the CEC licensing authority rather than Imperial County licensing authority. In addition, the CURE petition asks the court to investigate and halt any ongoing violation of the Warren Alquist Act by the Company, and to award CURE attorney’s fees and costs. As to North Brawley, CURE alleges that the CEC decision violated the Warren Alquist Act because it failed to consider provisions of the County permit for North Brawley, which CURE contends authorizes the Company to build a generating facility with a number of Ormat Energy Converters (“OECs”) capable of generating more than 50 MW. As to East Brawley, CURE alleges that the CEC decision violated the Warren Alquist Act because it failed to consider the conditional use permit application for East Brawley, which CURE contends shows that the Company requested authorization to build a facility with a number of OECs capable of generating more than 50 MW.

From time to time, the Company is named as a party in various other lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of its 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 24 — QUARTERLY FINANCIAL INFORMATION (UNAUDITED)


	Three Months Ended
	Mar. 31, 2011			June 30, 2011			Sept. 30, 2011			Dec. 31, 2011			Mar. 31, 2012			June 30, 2012			Sept. 30, 2012			Dec. 31, 2012
	(Dollars in thousands, except per share amounts)
Revenues:
Electricity	$	78,268		$	81,190		$	86,815		$	77,576		$	82,247		$	85,011		$	81,452		$	78,819
Product		19,552			23,424			24,026			46,158			50,105			44,826			54,685			37,263

Total revenues		97,820			104,614			110,841			123,734			132,352			129,837			136,137			116,082

Cost of revenues:
Electricity		65,937			62,212			57,941			57,947			57,931			57,953			61,466			67,284
Product		16,890			9,249			17,137			32,796			34,627			31,818			42,130			26,771

Total cost of revenues		82,827			71,461			75,078			90,743			92,558			89,771			103,596			94,055

Gross margin		14,993			33,153			35,763			32,991			39,794			40,066			32,541			22,027
Operating expenses:
Research and development expenses		2,207			2,575			2,346			1,673			1,048			1,464			1,436			2,160
Selling and marketing expenses		2,660			3,725			2,940			6,882			4,922			4,666			3,445			3,089
General and administrative expenses		7,007			7,479			6,269			7,130			7,314			6,793			6,208			7,952
Impairment charges		—			—			—			—			—			—			7,264			229,113
Write-off of unsuccessful exploration activities		—			—			—			—			768			1,151			—			720

Operating income (loss)		3,119			19,374			24,208			17,306			25,742			25,992			14,188			(221,007	)
Other income (expense):
Interest income		135			716			438			138			388			336			280			197
Interest expense, net		(13,080	)		(17,442	)		(23,909	)		(15,028	)		(14,878	)		(14,263	)		(15,400	)		(19,528	)
Foreign currency translation and transaction gains (losses)		517			596			(2,659	)		196			14			(1,756	)		615			1,369
Impairment of auction rate securities		—			—			—			—			—			—			—			—
Income attributable to sale of tax benefits		2,139			3,141			2,344			3,850			2,517			2,589			2,311			2,710
Other non-operating income (expense), net		(797	)		915			347			206			(161	)		290			215			246

Income (loss), before income taxes and equity in income (losses) of investees		(7,967	)		7,300			769			6,668			13,622			13,188			2,209			(236,013	)
Income tax benefit (provision)		(586	)		1,007			305			(49,261	)		(5,457	)		(4,309	)		(1,479	)		14,745
Equity in losses of investees		(412	)		(69	)		(71	)		(407	)		(140	)		(157	)		(1,245	)		(980	)

Net income (loss)		(8,965	)		8,238			1,003			(43,000	)		8,025			8,722			(515	)		(222,248	)
Net income attributable to noncontrolling interest		(10	)		(105	)		(137	)		(80	)		(130	)		(81	)		(67	)		(136	)

Net income (loss) attributable to the Company’s stockholders	$	(8,975	)	$	8,133		$	866		$	(43,080	)	$	7,895		$	8,641		$	(582	)	$	(222,384	)

Earnings (loss) per share attributable to the Company’s stockholders — basic and diluted	$	(0.20	)	$	0.18		$	0.02		$	(0.95	)	$	0.17		$	0.19		$	(0.01	)	$	(4.89	)

Weighted average number of shares used in computation of earnings (loss) per share attributable to the Company’s stockholders:
Basic		45,431			45,431			45,431			45,431			45,431			45,431			45,431			45,431

Diluted		45,431			45,443			45,440			45,431			45,437			45,438			45,431			45,431

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 25 — SUBSEQUENT EVENTS

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, LLC (“ORTP”), entitling JPM to certain tax benefits (such as PTCs and accelerated depreciation) associated with certain geothermal power plants in California and Nevada.

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. Should Ormat Nevada exercise this purchase option, it would thereupon revert to being sole owner of the power plants.

The Class B membership units entitle the holder to 5% (allocation of income and loss) and 2.5% (allocation of cash) residual economic interest in ORTP. The 5% and 2.5% residual interest commences on achievement by JPM of a contractually stipulated return that triggers the ORTP Flip Date. The actual ORTP Flip Date is not known with certainty. This residual 5% and 2.5% interest represents a noncontrolling interest and is 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.

Acquisition of OFC Senior Secured Notes

In February 2013, the Company acquired from OFC noteholders OFC Senior Secured Notes (see Note 11) with an outstanding aggregate principal amount of $12.8 million and will recognize a gain of $1.1 million in the first quarter of 2013.

OPIC loan

In February 2013, OrPower 4 received the remaining $45.0 million of Tranche II of the OPIC loan (see Note 11).

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ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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, 2012, 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.

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, 2012 using criteria established in Internal Control — Integrated Framework issued by the COSO and concluded that the Company maintained effective internal control over financial reporting as of December 31, 2012.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2012 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.

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PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information required by this Item in addition to that below is incorporated by reference herein from the Company’s definitive 2013 Proxy Statement.

Directors and Executive Officers Information

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
Gillon Beck		51	Chairman of the Board of Directors⁽³⁾
Lucien Y. Bronicki		78	Chief Technology Officer
Yehudit “Dita” Bronicki		71	Chief Executive Officer; Director⁽²⁾
Yoram Bronicki		46	President; Chief Operating Officer; Director⁽¹⁾
Joseph Tenne		57	Chief Financial Officer*
Nadav Amir		62	Executive Vice President — Operations*
Zvi Reiss		62	Executive Vice President — Project Management*
Zvi Krieger		57	Executive Vice President — Geothermal Resource*
Shimon Hatzir		51	Senior Vice President — Engineering*
Etty Rosner		57	Senior Vice President — Contract Management;
			Corporate Secretary*
Nir Wolf		47	Vice President — Business Development — Marketing and Sales, Rest of the World*
Dan Falk		68	Independent Director⁽³⁾
Ami Boehm		41	Independent Director⁽²⁾
Robert F. Clarke		70	Independent Director⁽²⁾
Robert E. Joyal		68	Independent Director⁽²⁾
David Granot		66	Independent Director⁽¹⁾

*	Performs the functions described in the table, but is employed by Ormat Systems

⁽¹⁾	Denotes Class I Director — Term expiring at 2014 Annual Shareholders Meeting

⁽²⁾	Denotes Class II Director — Term expiring at 2015 Annual Shareholders Meeting

⁽³⁾	Denotes Class III Director — Term expiring at 2013 Annual Shareholders Meeting

Gillon Beck. Gillon Beck has been a member of our Board of Directors since May 22, 2012. Since 2003, Mr. Beck has been a Senior Partner at FIMI Opportunity Funds, as well as a Director of the FIMI Opportunity Funds’ General Partners and SPV companies. In addition, Mr. Beck currently serves as Chairman of the Board of Ham-Let (Israel-Canada) Ltd., a company publicly-traded on the Tel Aviv Stock Exchange, and of Inrom Industries, Ltd. and H.R. Givon Ltd., both of which are private companies. He also serves as a member of the Board of Directors of Nirlat Paints, Ltd., Ytong Industries, Ltd., and Alony Ltd., companies which had been public companies but which have since become non-public companies. During the past five years, Mr. Beck formerly served as a member of the Board of Directors of the following public companies: Medtechnica, Ltd., Merhav Ceramic and Building Materials Center, Ltd., Retalix Ltd., Gamatronic Electronic Industries, Ltd., and Orian C.M. Ltd., Tedea, Ltd. From 1999 to 2003, Mr. Beck served as Chief Executive Officer and President of Arad Ltd., a publicly-traded water measurement and automatic meter reading company, and from 1995 to 1999, he served as Chief Operating Officer of Arad Ltd. Mr. Beck received a Bachelor of Science degree in Industrial Engineering in 1990 from the Technion — Israel Institute of Technology, and a Masters of Business Administration in Finance in 1992 from Bar-Ilan University.

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Lucien Y. Bronicki. Lucien Y. Bronicki has been our Chief Technology Officer since July 1, 2004. Mr. Bronicki co-founded Ormat Turbines Ltd. in 1965 and is a member of the Board of Directors of Ormat Industries Ltd., the publicly-traded successor to Ormat Turbines Ltd. Mr. Bronicki served as the Chairman of the Board of Directors of the Company until May 22, 2012, and served as the Chairman of the Board of Directors of Ormat Industries Ltd. and several of its subsidiaries until September 15, 2011. From 1992 to May 2006, Mr. Bronicki was the Chairman of the Board of Directors of Bet Shemesh Engines, a manufacturer of jet engines, and from 1997 to May 2006, Mr. Bronicki was the Chairman of the Board of Directors of Bet Shemesh Holdings. Mr. Bronicki was also the Chairman of the Board of Directors of Orad Hi-Tec Systems Ltd., a manufacturer of image processing systems, until the end of 2005, and was the Co-Chairman of Orbotech Ltd., a NASDAQ-listed manufacturer of equipment for inspecting and imaging circuit boards and display panels. From 1957 until 1958, Mr. Bronicki worked in the Nuclear Research Center in Saclay (France) designing equipment for elementary particle research at CERN. He went on to join the National Physical Laboratory of Israel and develop solar-powered turbines, which evolved into geothermal power plants. Mr. Bronicki has worked in the power industry since 1958. He is a member of the Executive Council of the Weizmann Institute of Science and was the Chairman of the Israeli Committee of the World Energy Council. Mr. Bronicki was also a member of the Studies Committee “Energy for Tomorrows World Commission” of the World’s Energy council. Yehudit Bronicki and Lucien Bronicki are married and are the parents of Yoram Bronicki. Mr. Bronicki obtained a postgraduate degree in Nuclear Engineering from Conservatoire National des Arts et Métiers, a Master of Science in Physics from Universite de Paris and a Master of Science in Mechanical Engineering from École Nationale Supérieure d’Ingenieurs Arts et Métiers. He received a Ph.D. Honoris Causa in 2005 from the Ben-Gurion University, in 2006 from the Weizmann Institute of Science, and in 2007 from the Technion — Israel Institute of Technology. Mr. Bronicki has received the Pioneers Award from the Geothermal Resources Council, and the Italian Geothermal Union Centenary Award.

Yehudit “Dita” Bronicki. Yehudit Bronicki has been our Chief Executive Officer since July 1, 2004, and is also a member of our Board of Directors. From July 1, 2004 to September 20, 2007, Mrs. Bronicki also served as our President. Mrs. Bronicki was a co-founder of Ormat Turbines Ltd. and is a member of the Board of Directors and the General Manager (a CEO-equivalent position) of Ormat Industries Ltd., the publicly traded successor to Ormat Turbines Ltd., and several of its subsidiaries. From 1992 to June 2005, Mrs. Bronicki was a director of Bet Shemesh Engines, a manufacturer of jet engines. In addition, since 2000, Mrs. Bronicki she has been a member of the Board of Orbotech Ltd., a NASDAQ-listed manufacturer of equipment for inspecting and imaging circuit boards and display panels. From 1994 to 2001, Mrs. Bronicki was on the Advisory Board of the Bank of Israel. Mrs. Bronicki has worked in the power industry since 1965. Yehudit Bronicki and Lucien Bronicki are married and are the parents of Yoram Bronicki. Mrs. Bronicki obtained a Bachelor of Arts in Social Sciences from Hebrew University in 1965. In 2007, she received a PhD. Honoris Causa from the Technion — Israel Institute of Technology.

Yoram Bronicki. Yoram Bronicki has been a member of our Board of Directors since November 12, 2004, and has been our President and Chief Operating Officer since September 20, 2007. From July 1, 2004 to September 20, 2007, Mr. Bronicki was our Chief Operating Officer, North America. Mr. Bronicki was also a member of the Board of Directors of Ormat Industries Ltd. from 2001 to May 2012. From 1999 to 2001, Mr. Bronicki was Project Manager of Ormat Industries Ltd. and Ormat International Inc.; from 1996 to 1999, he was Project Manager of Ormat Industries Ltd.; and from 1995 to 1996, he was Project Engineer of Ormat Industries Ltd. Mr. Bronicki is the son of Lucien and Yehudit Bronicki. Mr. Bronicki obtained a Bachelor of Science in Mechanical Engineering from Tel Aviv University in 1989 and a Certificate from the Technion Institute of Management Senior Executives Program.

Joseph Tenne. Joseph Tenne has served as our Chief Financial Officer since March 9, 2005. From 2003 to 2004, Mr. Tenne was the Chief Financial Officer of Treofan Germany GmbH & Co. KG, a German company. From 1997 until 2003, Mr. Tenne was a partner in Kesselman & Kesselman, Certified Public Accountants in Israel (a member firm of PricewaterhouseCoopers International Limited). Since January 8, 2006, Mr. Tenne has also been the Chief Financial Officer of Ormat Industries Ltd. Mr. Tenne is a member of the board of directors of

203

AudioCodes Ltd., a NASDAQ-listed company. Mr. Tenne obtained a Master of Business Administration from Tel Aviv University in 1987 and a Bachelor of Arts in Accounting and Economics from Tel Aviv University in 1981. Mr. Tenne is also a Certified Public Accountant in Israel.

Nadav Amir. Nadav Amir has served as our Executive Vice President of Operations since November 4, 2009. From July 1, 2004 to November 3, 2009, Mr. Amir was our Executive Vice President of Engineering; from 2001 to June 30, 2004, he was Executive Vice President of Engineering of Ormat Industries; from 1993 to 2001, he was Vice President of Engineering of Ormat Industries Ltd.; from 1988 to 1993, he was Manager of Engineering of Ormat Industries Ltd.; from 1984 to 1988, he was Manager of Product Engineering of Ormat Industries Ltd.; and from 1983 to 1984, he was Manager of Research and Development of Ormat Industries. Mr. Amir obtained a Bachelor of Science in Aeronautical Engineering from the Technion — Israel Institute of Technology in 1972.

Zvi Reiss. Zvi Reiss has served as our Executive Vice President of Project Management since July 1, 2004. From 2001 to June 30, 2004, Mr. Reiss was the Executive Vice President of Project Management of Ormat Industries Ltd.; from 1995 to 2000, he was Vice President of Project Management of Ormat Industries Ltd. and, from 1993 to 1994, he was Director of Projects of Ormat Industries Ltd. Mr. Reiss obtained a Bachelor of Science in Mechanical Engineering from Ben Gurion University in 1975.

Zvi Krieger. Zvi Krieger has served as our Executive Vice President of Geothermal Resource since November 4, 2009; from September 20, 2007 to November 3, 2009, Mr. Krieger was our Senior Vice President of Geothermal Engineering; from July 1, 2004 to September 20, 2007, he was our Vice President of Geothermal Engineering; and from 2001 to June 30, 2004, he was the Vice President of Geothermal Engineering of Ormat Industries Ltd. Mr. Krieger has been with Ormat Industries Ltd. since 1981 and served as Application Engineer, Manager of System Engineering, Director of New Technologies Business Development and Vice President of Geothermal Engineering. Mr. Krieger obtained a Bachelor of Science in Mechanical Engineering from the Technion – Israel Institute of Technology in 1980.

Shimon Hatzir. Shimon Hatzir has served as our Senior Vice President of Engineering since November 4, 2009. From September 20, 2007 to November 3, 2009, Mr. Hatzir was our Senior Vice President of Electrical and Conceptual Engineering; from July 1, 2004 to September 20, 2007, he was our Vice President of Electrical and Conceptual Engineering; from 2002 to June 30, 2004, he was the Vice President of Electrical and Conceptual Engineering of Ormat Industries Ltd; from 1996 to 2001, he was Manager of Electrical and Conceptual Engineering of Ormat Industries Ltd.; and from 1989 to 1995, he was a Project Engineer in the Engineering Division. Mr. Hatzir obtained a Bachelor of Science in Mechanical Engineering from Tel Aviv University in 1988 and a Certificate of the Technology Institute of Management, Senior Executive Program.

Etty Rosner. Etty Rosner has served as our Corporate Secretary since October 21, 2004. Ms. Rosner is also the Corporate Secretary of Ormat Industries Ltd., a position she has held since 1991. Ms. Rosner is also our Senior Vice President of Contract Management since September 20, 2007; from July 1, 2004 to September 20, 2007, Ms. Rosner was our Vice President of Contract Management; from 1999 to June 30, 2004, she was the Vice President of Contract Management of Ormat Industries Ltd; from 1991 to 1999, she was Contract Administration Manager and Corporate Secretary of Ormat Industries; and from 1981 to 1991, she was the Manager of the Export Department and Office Administrative Manager of Ormat Industries. Ms. Rosner obtained a Diploma in General Management from Tel Aviv University in 1990.

Nir Wolf. Nir Wolf has served as our Vice President for Business Development — Marketing and Sales, Rest of the World since January 1, 2010. From December 2005 to December 31, 2009, Mr. Wolf served as our Vice President, Distributed Power responsible for the marketing, sales, engineering and after sales activities of the remote power units. From December 1999 to December 2005, Mr. Wolf had a leading position as Business Development Manager in the Marketing and Sales Department. Starting January 14, 1994, when Mr. Wolf joined us, he was positioned in the Project Management Department as a Budget and Schedule Controller and later on as

204

a Project Manager. Mr. Wolf obtained a Bachelor of Science in Industrial Engineering, cum laude from the Technion — Israel Institute of Technology in 1991. In 1995, Mr. Wolf obtained a Master of Business Administration from the Bar Ilan University. Mr. Wolf participated in the Technion Institute of Management Senior Executive Program.

Dan Falk. Dan Falk has been a member of our Board of Directors since November 12, 2004. Mr. Falk also serves as the Chairman of the Board of Directors of Orad Hi-Tech Systems Ltd., a public non-U.S. company. He is also a member of the Board of Directors of Orbotech Ltd., Nice Systems Ltd., Attunity Ltd., and Nova Measuring Instruments Ltd., all NASDAQ publicly traded companies. In addition, Mr. Falk serves as a member of the Board of Directors of the following public non-U.S. companies: Amiad Water Systems Ltd., and Plastopil Ltd. During the past five years, Mr. Falk served as a member of the Board of Directors of the following public companies, for which he no longer serves as a Director: AVT Ltd., Clicksoftware Technologies Ltd., Dmatek Ltd., Jacada Ltd., Oriion Medical Ltd., Poalim Ventures I Ltd., and Medcon Ltd. From 2001 to 2004, Mr. Falk was a business consultant to several public and private companies. From 1999 to 2000, Mr. Falk was Chief Operating Officer and Chief Executive Officer of Sapiens International N.V. From 1995 to 1999, Mr. Falk was an Executive Vice President of Orbotech Ltd. From 1985 to 1995, Mr. Falk was Vice President of Finance and Chief Financial Officer of Orbot Systems Ltd. and Orbotech Ltd. Mr. Falk obtained a Masters of Business Administration from Hebrew University in 1972 and a Bachelor of Arts in Economics and Political Science from Hebrew University in 1968. Mr. Falk is the Chair of our Audit Committee.

Ami Boehm. Ami Boehm has been a member of our Board of Directors since May 22, 2012. Since 2004, Mr. Boehm has been a Partner at FIMI Opportunity Funds, as well as Managing Partner and CEO of FITE GP (2004). In addition, Mr. Boehm currently serves as a member of the Board of Directors of Gilat Satellite Networks Ltd., a NASDAQ publicly-traded company, and of the following non-U.S. public companies: Scope Metal Trading, Ltd., Ham-Let (Israel Canada Ltd., and Inter Industries, Ltd. He also serves as a member of the Board of Directors of Inter-Electric, Ltd., a private company. During the past five years, Mr. Boehm formerly served as a member of the Board of Directors of the following non-U.S. public companies: Global Wire Ltd. and Telkoor Telecom Ltd. From 1999 to 2004, Mr. Boehm served as Head of Research at Discount Capital Markets, the investment arm of Israel Discount Bank, and from 1998 to 1999, he worked in the Office of the Attorney General in the Israeli Ministry of Justice. Mr. Boehm received a Bachelor of Law degree in 1997 from Tel Aviv University, a Bachelor of Arts degree in Economics in 1998 from Tel Aviv University, and a Masters of Business Administration in Finance in 2004 jointly from Northwestern University’s Kellogg School of Business and Tel Aviv University.

Robert F. Clarke. Robert F. Clarke has been a member of our Board of Directors since February 27, 2007. Mr. Clarke was Chairman (since September 1998) and President and Chief Executive Officer (since January 1991) of Hawaiian Electric Industries, Inc. (HEI), from which he retired effective May 2006. Since June 1, 2006, Mr. Clarke has been Executive in Residence at the Shidler College of Business at the University of Hawaii. In addition, Mr. Clarke serves as an advisory director to Oceanic Cable Hawaii, and as a member of the advisory boards of the Shidler College of Business at the University of Hawaii, Sennet Capital, and Aina Koa Pono, a Hawaii based privately held company exploring renewable energy projects in converting biomass into fuels. Mr. Clarke joined HEI in February 1987 as Vice President of Strategic Planning and was in charge of implementing the Company’s diversification strategy. Mr. Clarke was named HEI Group Vice President — Diversified Companies in May 1988. He was made a director of HEI in 1989. Prior to joining HEI, Mr. Clarke served as Senior Vice President and Chief Financial Officer of Alexander & Baldwin and as Controller of Dillingham Corporation. Prior to that, he worked for the Ford Motor Company and for the Singer Company. He received his Bachelor’s degree in economics in 1965 and his Master’s degree in finance in 1966 from the University of California at Berkeley. Honors include Phi Beta Kappa in 1965.

Robert E. Joyal. Robert E. Joyal has been a member of our Board of Directors since May 22, 2012. Since 2006, Mr. Joyal has served as a Director of Jefferies Group, Inc., a public company. Since 2003, Mr. Joyal has served as a member of the Board of Trustees of the following investment funds: MassMutual Funds, Babson

205

Capital Corporate Investors, and Babson Capital Participation Investors. Mr. Joyal also serves as a Director of FIMI 2001 Ltd. and FITE 2004 Ltd., and is a member of the investment committee of various funds sponsored by FIMI. He has also been a director of Kimco Insurance Company since 2007, and a member of the Board of Trustees of First Israel Mezzanine Investors since 2003. During the past five years, Mr. Joyal served as a member of the Board of Directors of the following public companies, for which he no longer serves as a Director: Alabama Aircraft Industries Inc. and Scottish Re Group Ltd. Mr. Joyal is a Chartered Financial Analyst. He earned a BA from St. Michael’s College and a MBA from Western New England College.

David Granot. David Granot has been a member of our Board of Directors since May 22, 2012. Since 2007, Mr. Granot has served as Chairman of Scorpio Real Estate, a non-U.S. public company. In addition, he is a member of the Board of the following non-U.S. public companies: Harel Insurance Investments and Financial Services Ltd.; Alrov Israel; and Ham-let, a member of the IDB Group. He also serves on the Board of the following private companies: BSG Capital Markets Ltd., the holding company of the financial assets of the BSG Group, and G.D. Goren Management and Consultation Ltd. During the past five years, Mr. Granot served as a member of the Board of Directors of the following non-U.S. public companies, for which he no longer serves as a Director: Tempo Beverages Ltd. and Bateman Litwin N.V. From 2001 through 2007, Mr. Granot served as the CEO of the First International Bank of Israel Ltd. He earned a BA in Economics and a MBA from the Hebrew University in Jerusalem.

Audit Committee

The information required under this section is incorporated by reference herein from the Company’s definitive 2013 Proxy Statement.

ITEM 11.

EXECUTIVE COMPENSATION

The information required under this item is incorporated by reference herein from the Company’s definitive 2013 Proxy Statement.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required under this item is incorporated by reference herein from the Company’s definitive 2013 Proxy Statement.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required under this item is incorporated by reference herein from the Company’s definitive 2013 Proxy Statement.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required under this item is incorporated by reference herein from the Company’s definitive 2013 Proxy Statement.

206

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.

207

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/ YEHUDIT BRONICKI
		Name: Yehudit Bronicki
		Title: Chief Executive Officer and Director

Date: March 11, 2013

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 11, 2013.


Signature		Capacity

/S/ YEHUDIT BRONICKI Yehudit Bronicki		Chief Executive Officer and Director (Principal Executive Officer)

/S/ JOSEPH TENNE Joseph Tenne		Chief Financial Officer (Principal Financial and Accounting Officer)

/S/ GILLON BECK Gillon Beck		Chairman of the Board of Directors

/S/ YORAM BRONICKI Yoram Bronicki		President, Chief Operating Officer and Director

/S/ AMI BOEHM Ami Boehm		Director

/S/ DAN FALK Dan Falk		Director

208

(C)

EXHIBIT INDEX


Exhibit 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 to 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.

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.

209


Exhibit No.		Document

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.

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.

210


Exhibit No.		Document

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.

10.2.1		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.

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.

211


Exhibit No.		Document

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.

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.

212


Exhibit No.		Document

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.

213


Exhibit No.		Document

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.

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.

214


Exhibit No.		Document

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.

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.

215


Exhibit No.		Document

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.

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.

216


Exhibit No.		Document

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.

217


Exhibit No.		Document

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.

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		Form of Executive Employment Agreement of Lucien Bronicki incorporated by reference to Exhibit 10.7 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

10.6.2		Amendment to Employment Agreement of Lucien Bronicki, dated March 21, 2012 between Ormat Technologies, Inc. and Lucien 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 March 21, 2012.

218


Exhibit No.		Document

10.6.3		Waiver executed by Lucien Bronicki in favor of Ormat Technologies, Inc., dated May 22, 2012, filed herewith.

10.6.4		Undertaking executed by Lucien Bronicki in favor of Ormat Industries Ltd. and Ormat Technologies, Inc., dated May 22, 2012, filed herewith.

10.7.1		Form of Executive Employment Agreement of Yehudit Bronicki incorporated by reference to Exhibit 10.8 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.

10.7.2		Amendment to Employment Agreement of Yehudit Bronicki, dated March 28, 2008, by and between Ormat Technologies, Inc. and Yehudit 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.

10.7.3		Second Amendment to Employment Agreement of Yehudit Bronicki, dated March 21, 2012 between Ormat Technologies, Inc. and Yehudit Bronicki, incorporated by reference to Exhibit 10.2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on March 21, 2012.

10.7.4		Waiver executed by Yehudit Bronicki in favor of Ormat Technologies, Inc., dated May 22, 2012, filed herewith.

10.7.5		Undertaking executed by Yehudit Bronicki in favor of Ormat Industries Ltd. and Ormat Technologies, Inc., dated May 22, 2012, filed herewith.

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.

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, filed herewith.

10.8.5		Undertaking executed by Yoram Bronicki in favor of Ormat Industries Ltd. and Ormat Technologies, Inc., dated May 22, 2012, filed herewith.

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.

219


Exhibit No.		Document

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.

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.

220


Exhibit No.		Document

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.

221


Exhibit No.		Document

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.

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., filed herewith.

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, filed herewith.

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.

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.

222


Exhibit No.		Document

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.

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.

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