ORA 10-K Annual Report Dec. 31, 2009

ORMAT TECHNOLOGIES, INC.

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10-K 1 y83042e10vk.htm FORM 10-K e10vk

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, 2009
or
o		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)

Registrant’s telephone number, including area code:

(775) 356-9029

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


Title of Each Class		Name of Each Exchange on Which Registered

Ormat Technologies, Inc. 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 o 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 o 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 o

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 o No o

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. o

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 þ		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

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

As of June 30, 2009, 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 $804,492,831 based on the closing price as reported on the New York Stock Exchange.

The number of outstanding shares of common stock of the registrant, as of March 4, 2010, 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, 2009.

ORMAT TECHNOLOGIES, INC.

FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2009

TABLE OF CONTENTS


			Page No.

PART I
	ITEM 1.	BUSINESS		9
	ITEM 1A.	RISK FACTORS		64
	ITEM 1B.	UNRESOLVED STAFF COMMENTS		80
	ITEM 2.	PROPERTIES		80
	ITEM 3.	LEGAL PROCEEDINGS		81

PART II
	ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		82
	ITEM 6.	SELECTED FINANCIAL DATA		84
	ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		87
	ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		119
	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		120
	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		180
	ITEM 9A.	CONTROLS AND PROCEDURES		180
	ITEM 9B.	OTHER INFORMATION		181

PART III
	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		181
	ITEM 11.	EXECUTIVE COMPENSATION		184
	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		184
	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		185
	ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES		185

PART IV
	ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES		185
SIGNATURES				197
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2

Glossary of Terms

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:


Term		Definition

Adder		Additional energy rate payment
Amatitlan Loan		$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
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
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.
CDC		Commonwealth Development Corporation
CNE		National Energy Commission of Nicaragua
CNEE		National Electric Energy Commission of Guatemala
Company		Ormat Technologies, Inc., a Delaware corporation, and subsidiaries
Codification		FASB Accounting Standards Codification
COSO		Committee of Sponsoring Organizations of the Treadway Commission
DEG		Deutsche Investitions-und Entwicklungsgesellschaft mbH
DFIs		Development Finance Institutions
DISNORTE		Empresa Distribudora de Electricidad del Norte (a Nicaragua distribution company)
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
EGS		Enhanced Geothermal Systems
ENATREL		Empresa Nicaraguense de Transmision
ENEL		Empresa Nicaraguense de Electricitdad
EPA		U.S. Environmental Protection Agency
EPC		Engineering, procurement and construction
EPS		Earnings per share
Exchange Act		U.S. Securities Exchange Act of 1934, as amended
FASB		Financial Accounting Standards Board
FERC		U.S. Federal Energy Regulatory Commission


Term		Definition

Flip Date		Date on which the holders of Class B membership units in OPC achieve a target after-tax yield on their investment in OPC.
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
HELCO		Hawaii Electric Light Company
IFC		International Finance Corporation
IID		Imperial Irrigation District
ILA		Israel Land Administration
INDE		Instituto Nacional de Electrification
INE		Nicaragua Institute of Energy
IPPs		Independent Power Producers
ISO		International Organization for Standardization
ITC		Investment Tax Credit
KETRACO		Kenya Electricity Transmission Company Limited
KPL		Kapoho Land Partnership
KPLC		Kenya Power and Lighting Co. Ltd
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
MACRS		Modified Accelerated Cost Recovery System
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
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 1 / 4 % Senior Secured Notes Due 2020 issued by OFC
Olkaria Loan		$105,000,000 in aggregate principal amount borrowed by OrPower 4 from a group of European DFIs
OMPC		Ormat Momotombo Power Company, a wholly owned subsidiary of the Company
OPC		OPC LLC
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.
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


Term		Definition

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 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
Orgumil		Orgumil I de Electricidad, Limitada, a wholly owned subsidiary of the Company
Parent		Ormat Industries Ltd.
PGV		Puna Geothermal Venture, a wholly owned subsidiary of the Company
Power plant equipment		Interconnection equipment, cooling towers for water cooled power plant, etc.
Power Act		Electric Power Act of 1997 of Kenya
PPA		Power Purchase Agreement
ppm		Part per million
PLN		PT Perusahaan Listrik Negara
PTC		Production tax credit
PUA		Israeli Public Utility Authority
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
PV		Photovoltaic
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.
REG		Recovered Energy Generation
RGGI		Regional Greenhouse Gas Initiative


Term		Definition

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
SOX Act		Sarbanes-Oxley Act of 2002
SPE(s)		Special purpose entity (ies)
Sunday Energy		Sunday Energy Ltd.
Union Bank		Union Bank, N.A.
U.S.		United States of America
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 report are primarily located in the material set forth under the headings “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in Part II, Item 7, “Risk Factors” contained in Part I, Item IA, and “Notes to Financial Statements” contained in Part II, Item 8 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. 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;

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

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

	•	financial market conditions and the results of financing efforts;

	•	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 authorization;

	•	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;

	•	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 and incentives for the production of renewable energy in the United States and elsewhere;

	•	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 similar geothermal energy projects, including any such new geothermal energy projects developed in the future, and from alternative electricity producing technologies;


	•	the effect of and changes in economic conditions in the areas in which we operate;

	•	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 terrorist incidents or responses to such incidents, including the effect on the availability of and premiums on insurance;

	•	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 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 two business segments, which we refer to as our Electricity Segment and Product Segment. In our Electricity 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. In our Product 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 power plants.

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

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, 2009. 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 revenues for the year ended December 31, 2009:

The following chart sets forth the geographical breakdown of the revenues attributable to our Electricity Segment for the year ended December 31, 2009:

The following chart sets forth the geographical breakdown of the revenues attributable to our Product Segment for the year ended December 31, 2009:

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. Therefore, electricity produced from geothermal energy sources contributes significantly less to local and regional incidences of acid rain and global warming 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 power plants. Recovered energy represents residual heat that is generated as a by-product of gas turbine-driven compressor stations 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.

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. 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

Power Plants in Operation

The table below summarizes certain key non-financial information relating to our power plants as of February 28, 2010.


Power Plants We Own and Operate ⁽¹⁾
		Generating
		Capacity in
Project	Location	MW ⁽²⁾

Domestic
Geothermal
Ormesa Complex	California		57.0
Heber Complex	California		92.0
Mammoth Complex	California		14.5	⁽³⁾
North Brawley	California		50.0	⁽⁴⁾
Steamboat Complex	Nevada		85.0
Brady Complex	Nevada		24.0
Puna	Hawaii		30.0
REG
OREG 1	North Dakota and South Dakota		22.0
OREG 2	Montana, North Dakota and Minnesota		22.0
Peetz	Colorado		3.5

Total domestic owned facilities			400.0

Foreign
Geothermal
Momotombo	Nicaragua		26.0
Zunil	Guatemala		24.0
Olkaria III Complex	Kenya		48.0
Amatitlan	Guatemala		20.0

Total foreign owned facilities			118.0

Total domestic and foreign owned facilities			518.0


⁽¹⁾		We own and operate all but two of our power plants. Those exceptions are: 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, and the Mammoth complex, in which we have a 50% ownership interest. A financial institution holds equity interests in one of our consolidated subsidiaries (OPC) that 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. In this chart, we show these power plants as being 100% owned because all of the generating capacity is owned by OPC and we control the operation of the power plants. The nature of the equity interests held by the financial institution is described in Item 7 under the heading “OPC Transaction”.

⁽²⁾		References to generating capacity generally refer to the gross capacity less auxiliary power, in the case of all of our existing domestic power plants and the Momotombo, Amatitlan and Olkaria III power plants (three of our foreign power plants), and to the generating capacity that is subject to the “take or pay” PPAs in the case of the Zunil power plant (one of our foreign power plants). We determine the generating capacity figures taking into account resource capabilities. 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 the geothermal power plants in commercial operation in 2009 was 90%; the corresponding availability of the power generating facility was higher than 97%. The capacity factor of the REG power plants in 2009 was 40%; the corresponding availability of the power generating equipment was more than 93%.

⁽³⁾		Represents our 50% ownership.

⁽⁴⁾		The North Brawley power plant is not operating at full capacity due to injection challenges we are experiencing. Detailed information on those challenges is provided under Description of our Power Plants.

Substantially all of the revenues that we currently derive from the sale of electricity are pursuant to long-term power purchase agreements. Approximately 62% of our total revenues in the year ended December 31, 2009 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 development of new power plants, construction of new power plants and expansion of existing power plants. Our growth plan includes approximately 260 MW in generating capacity from geothermal power plants and from recovered energy power plants in the United States that are expected to come on-line in the next four years.

We have various leases and concessions for geothermal resources of approximately 290,000 acres in 22 sites. We have started or plan to start exploration activity at a number of these sites.

In addition, we have approximately 55 MW of solar PV projects under development in Israel (including 36 MW in a joint venture with Sunday Energy).

Our Product Business

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 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 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 climate conditions, whether hot or cold. 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 by Ormat Industries Ltd. (also referred to in this annual report as the “Parent”, “Ormat Industries”, “the parent company”, or “our parent”) in 1994. 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 56.0% 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. The energy necessary to operate a geothermal power plant is typically obtained from several such wells which are drilled using established technology that is in some respects similar to that employed in the oil and gas industry. Geothermal production wells are normally located within approximately one to two miles of the power plant as geothermal fluids cannot be transported economically 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 24hr/day weather independent power, the variable operating costs are lower.

EGS — An EGS has been broadly defined as a subsurface system that may be artificially created to extract heat from hot rock where the characteristics required for a hydrothermal system, i.e., permeability and aquifers, are non-existent. A geothermal power plant that uses EGS techniques would recover 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. This application is referred to as “Co-produced Fluids”. 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 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 heat exchanger, which heats a secondary working fluid which has a low boiling point. 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. The condensed fluid is then recycled back to the heat exchanger, closing the cycle within the sealed system. The cooled geothermal fluid is then reinjected back into the reservoir. The binary technology is depicted in the graphic below.

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 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 graphic below.

In some instances, the wells directly produce dry steam (the flashing occurring underground). In such cases, the steam is fed directly to the steam turbine and the rest of the system is 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 only or in combination with, various other commonly used thermodynamic technologies that convert heat to mechanical power. 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 our motive fluids 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. In particular, 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 recovered energy systems and new motive fluids.

We also construct 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. Our combined cycle technology is depicted in the graphic below.

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 tower 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 round per minute, 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 industry. 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. The same advantages of using the Organic Rankine Cycle apply here as well. In addition, our technology allows for better load following than conventional steam turbines exhibit, requires no water treatment as it is air cooled, and does not require the continuous presence of a steam licensed operator on site.

Our REG technology is depicted in the graphic below.

Patents

More than 75 United States patents (and about 18 pending patents) cover our products (mainly power units based on the Organic Rankine Cycle) and systems (mainly geothermal power plants and industrial waste heat recovery for electricity production). The systems-related patents cover not only a particular component but also the overall effectiveness of the plant’s systems from the “fuel” (e.g., geothermal fluid, waste heat, biomass or solar) to generated electricity. The duration of such patents ranges from one year to fifteen years. No single patent on its own is material to our business.

The products-related patents cover components such as turbines, heat exchanges, seals and controls. The system patents cover subjects such as 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 the 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.

Research and Development

We are conducting research and development of new EGS technologies and their application to our power plants. We are undertaking this development effort in cooperation with GeothermEx Inc., the University of Utah Energy & Geoscience Institute, the University of Nevada-Reno, and the Great Basin Center for Geothermal Energy, with funding support from the DOE, at our Desert Peak 2 and Brady power plants in Nevada.

We are developing an OEC unit for a REG plant designed to use the residual energy from the vaporization process of LNG in LNG receiving terminals. The power plant takes advantage of the available hot and cold sources (sea water and LNG at minus 238 degrees Fahrenheit, respectively) in the regasification process to generate electrical power from unused heat energy.

In another activity we are examining modifications to the cooling towers and equipment design that will help to reduce the water consumption and costs for cooling towers operating in existing power plants and future projects.

Market Opportunity

Interest in geothermal energy in the United States has increased as production costs for electricity generated from geothermal resources have become more competitive relative to fossil fuel-based electricity generation and as legislative and regulatory incentives have become more prevalent, as described below.

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

The Western Governors Association estimates that 13,000 MW of identified resources will be developed by 2025. In a report issued in January 2009, the Geothermal Energy Association identified 132 new geothermal projects under various phases of development in 14 U.S. States that have between 4,250 MW and 6,400 MW potential capacity. Approximately 45% of the identified capacity is in the initial phase of exploration.

An additional factor fueling recent growth in the renewable energy industry is 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, Arizona, California, Colorado, Connecticut, Delaware, Hawaii, Illinois, Kansas, Iowa, Maine, Maryland, Massachusetts, Michigan, Minnesota, Missouri, Montana, New Hampshire, Nevada, New Jersey, New Mexico, New York, North Carolina, North Dakota, Oregon, Ohio, Pennsylvania, Rhode Island, South Dakota, Texas, Utah, Virginia, Vermont, Washington, West Virginia, Wisconsin and the District of Colombia have all 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.

Twenty-eight 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 are located) and the District of Columbia define geothermal resources as “renewable”.

According to the EPA, fourteen states have enacted RPS and Alternative Portfolio Standards that include some form of combined heat and power and/or waste heat recovery. The fourteen states are: Colorado, Connecticut, Hawaii, Massachusetts, Michigan, Nevada, North Carolina, North Dakota, Ohio, Pennsylvania, South Dakota, Utah, Washington, and West Virginia.

We believe that these legislative measures and initiatives present a significant market opportunity for us. For example, California generally requires that each investor-owned electric utility company operating within the state increase the amount of renewable generation in its resource mix by at least 1% of its retail sales annually so that 20% of its retail sales are procured from eligible renewable energy sources by 2010. In November 2008, California, by Executive Order, adopted a goal for all retailers of electricity to serve 33% of their load with renewable energy by 2020. Governor Arnold Schwarzenegger signed an Executive Order on September 15, 2009, directing the California Air Resources Board to adopt regulations increasing California’s RPS to 33% by 2020. California’s three large electric utilities collectively served 13% of their 2008 electricity retail sales with renewable power. Nevada’s RPS requires each Nevada electric utility to obtain 12% of its annual energy requirements from renewable energy sources in 2009-2010, which requirement thereafter increases by 3% every two years until 2015, when 20% of such annual energy requirements must be provided from renewable energy sources or energy efficiency projects. As of March 2009, 9% of the electricity retail sales in Nevada were from renewable energy sources. Hawaii’s RPS requires each Hawaiian electric utility to obtain 10% of its net electricity sales from renewable energy sources by December 31, 2010, 15% by December 31, 2015 and 20% by December 31, 2020. In 2008, Hawaiian Electric Company and its subsidiaries achieved a consolidated RPS of 17.8%.

On the federal level, climate change legislation has been approved in the House of Representatives and similar legislation has been proposed in the Senate. In 2009, the EPA issued an “endangerment” finding under the Clean Air Act for greenhouse gases. This finding allows EPA to promulgate regulations in connection with emissions of greenhouse gases.

Regional initiatives are also being developed to reduce greenhouse gas emissions and develop trading systems for renewable energy credits. For example, ten Northeast 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. The first-in-the-nation auction of carbon dioxide allowances was held in September 2008. Under RGGI, the ten participating states plan to reduce carbon emissions from power plants by 10% by 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 greenhouse gas emissions, we believe they will prove advantageous to us.

The federal government also encourages production of electricity from geothermal resources through certain tax subsidies. Under the ARRA, we are permitted to claim 30% of the qualified cost of the equipment and construction of each new geothermal power plant in the United States, when such plant is placed in service as an ITC against our federal income taxes. Alternatively, we are permitted to claim a PTC, which in 2009 was 2.1 cents per kWh and which is adjusted annually for inflation. The PTC may be claimed for ten years on the electricity output from any new geothermal power plants put into service prior to 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 one-year carry back and a twenty-year carry forward. Another alternative available is a cash grant in lieu of the tax credits (ITC and PTC), for the amount of the ITC. That option will be available for projects placed in service in 2010, or that started construction during 2009 or 2010 and are completed by 2013. There have been several legislative efforts to extend this cash grant program, one of which would use a refundable tax credit modeled on the grant program. Whether we claim the PTC or the ITC, we are 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 we claim the ITC or receive the cash grant, our tax basis in the plant that we can recover through depreciation must be reduced by half of the tax credit or cash grant; if we claim a PTC, there is no reduction in the tax basis for depreciation.

Collectively, these tax 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.

Production of electricity from geothermal resources is also supported under the new “Temporary Program For Rapid Deployment of Renewable Energy and Electric Power Transmission Projects” established with the DOE as part of the DOE’s existing Innovative Technology Loan Guarantee Program. The new program (i) extends the scope of the existing federal loan guarantee program to cover renewable energy projects, renewable energy component manufacturing facilities and electricity transmission projects that embody established commercial, as well as innovative, technologies; and (ii) provides an appropriation to cover the “credit subsidy costs” of such projects (meaning the estimated average costs to the federal government from issuing the loan guarantee, equivalent to a lending bank’s loan loss reserve).

To be eligible for a guarantee under the new program, a supported project must break ground, and the guarantee must be issued by September 30, 2011. A project supported by the federal guarantee under the new program must pay prevailing federal wages.

Operations outside of the United States may be subject to and/or benefit from requirements under the Kyoto Protocol.

On December 7, 2009 the United Nations Climate Change Conference, commonly known as the Copenhagen Summit, was held in Copenhagen, Denmark. The conference included the 15th Conference of the Parties to the United Nations Framework Convention on Climate Change and the fifth Meeting of the Parties to the Kyoto Protocol. The U.S., China, India, Brazil, and South Africa signed up to the Copenhagen Accord which recognized that climate change is one of the greatest challenges of the present day and that actions should be taken to keep any temperature increases to below 2 degrees Celsius. While the document is not legally binding and does not contain any legally binding commitments for reducing CO ₂ emissions, the conference is another step in the direction of a binding agreement on climate change and may be consolidated at the next Conference of the Parties meeting in Mexico City later this year.

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, Guatemala, where our Zunil and Amatitlan power plants are located, approved in November 2003 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. Another example is New Zealand, where Ormat has been actively designing and supplying geothermal power solutions since 1986. The New Zealand government’s policies to fight climate change include a target for greenhouse gas 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 2nd 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, geothermal projects regulations have been implemented providing for incentives such as investment tax credits and accelerated depreciation, and pricing guidelines intended to allow preferential power prices from generators. 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 has committed at the United Natopn Climate Change Conference 2009 in Copenhagen to reduce its CO ₂ emissions by 20% by 2020, which is intended to be achieved mainly through prevention of deforestation and accelerated renewable energy development. Another example is Chile, where we were recently awarded an exploration concession. The Chilean Renewable Energy Act of 2008 requires that 5% of electricity sold come from renewable sources beginning in 2010, increasing gradually to 10% by 2024.

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 will benefit from the increased attention to energy efficiency. For example, in the United States, the FERC has expressed its position that the primary goal of natural gas pipeline design should be the efficient, low-cost transportation of fuel, including 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 requested natural gas pipeline operators filing for a certificate of approval for new pipeline construction or expansion projects to discuss “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 begun to build 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.

Further supporting recovered energy-based power generation, several states, as well as the federal government, have recognized the environmental benefits of recovered energy-based power generation. For example, Colorado, Connecticut, Hawaii, Massachusetts, Nevada, North Carolina, North Dakota, Ohio, Pennsylvania, South Dakota, Utah, and Washington allow electric utilities to include recovered energy-based power generation in calculating their compliance with RPS. In addition, 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 (whether in those two states or elsewhere in the United States) for federally funded, low interest loans, but currently do not qualify for ITC. Recovery of waste heat is also considered “environmentally friendly” in the western Canadian provinces. We believe that the European market has similar potential and we expect to leverage our early success in North America in order to expand into Europe and other markets worldwide. In North America alone, we estimate the potential total market for recovered energy-based power generation to be over 1,000 MW. However, much of this potential is in states where the cost of electricity is relatively low, which creates marketing challenges.

Competitive Strengths

Competitive Assets. Our assets are competitive for the following reasons:


	•	Contracted Generation. Virtually all of the electricity generated by our geothermal power plants is currently sold pursuant to long-term PPAs, providing generally predictable cash flows.

	•	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. We have a competitive advantage over other renewable energy sources, such as wind power, solar power or hydro-electric power (to the extent dependent on precipitation), which compete with us to meet electric utilities’ renewable portfolio requirements but which cannot serve baseload capacity because of their weather dependence and thus intermittent nature of these other renewable energy sources.

	•	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 compared to electricity generated from fossil fuels or other renewable sources under existing economic conditions and existing tax and regulatory regimes.

	•	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 our exploration, development, and construction activities, to a certain level, without the need to tap into external liquidity sources. We believe that this gives us a competitive advantage over certain competitors whose activities are dependent on external credit and financing sources, particularly in light of the current global credit and financial crisis.

	•	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 most of the equipment 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.


	•	We design, manufacture, and sell to third parties power units and other power generating equipment for geothermal and recovered energy-based electricity generation. Our extensive experience in the development of state-of-the-art, environmentally sound power solutions enable our customers to relatively easily finance their power plants.


	•	Exploration and Drilling Capabilities. We have in-house capabilities to explore and develop geothermal resources. In 2007, we established a drilling subsidiary that currently owns four drilling rigs. We employ an experienced resource group that includes engineers, geologists, and drillers. This resource group 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 more than 75 U.S. patents relating to various processes and renewable resource technologies. All of our patents are internally developed and therefore costs related thereto are expensed as incurred. 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.

	•	No 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 and the drilling of wells is complete, 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 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:


	•	Development and Construction of New Geothermal Power Plants — continuously seeking out commercially exploitable geothermal resources, developing and constructing new geothermal and recovered energy-based 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;

	•	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;

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

	•	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


	•	Technological Expertise — investing in research and development of renewable energy technologies including in the solar energy field 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.

We are also considering various opportunities in the solar energy market in addition to our activity in research and development in the solar field. There are several reasons for this including:


	•	the recent decline in the cost of solar PV technologies;

	•	the attractive electricity prices that may be achieved in certain jurisdictions;

	•	reliance on our EPC and development expertise in geothermal and recovered-energy power generation facilities; and

	•	in certain applications the potential synergies for operating solar PV or solar thermal in conjunction with our geothermal power plants.

Among other things, we have considered, and expect to continue considering, a number of different opportunities including:


	•	acquisitions and joint ventures;

	•	expanding our internal research and development activity, or acquiring other companies engaged in solar research and development activities; and

	•	constructing and operating solar electric power generation facilities, either:


	•	at some of our current plants to augment power output during day-time hours of peak demand when geothermal capacity can decrease because of ambient air temperature and solar generation capacity tends to peak; or

	•	at new locations on a stand-alone basis.

For example, as noted below, we entered into a joint venture with Sunday Energy for 36 MW PV energy systems in Israel. We have considered, and expect to continue to consider, various acquisition opportunities of companies engaged in various segments of the solar energy power generation business.

Recent Developments


	•	In February 2010, we signed a letter of intent with KPLC, the off-taker, of the Olkaria III complex located in Naivasha, Kenya, to expand the Olkaria III complex by up to 52 MW (from 48 MW to up to 100 MW) within the framework of the existing PPA. The expansion is to be developed in two phases. Phase I will be comprised of 36 MW within 3.5 years from finalizing the amendment to the existing PPA. An optional phase II may be comprised of up to 16 MW within 4.5 years from finalizing the amendment to the existing PPA. The amendment to the existing PPA is subject to applicable governmental approvals and the consent of the lenders that provided the financing to the existing power plant.

	•	In February 2010, we announced that the North Brawley geothermal power plant in California has been placed in service and is currently operating at a stable capacity of 17 MW. We plan to request the PPA off-taker to agree to an extension of the firm operation date to the end of the year. This extension would give us time to bring the power plant’s generation to its full design capacity of 50MW. Further details on this plant’s status are provided under “Description of Our Power Plants” below.

	•	In February 2010, we signed an agreement to acquire 100% of the membership interests in HSS II, LLC, which owns the Tuscarora Project in the northern Independence Valley of northeast Nevada. The project is in an advanced stage of development and has one successful well. We plan to construct and operate a geothermal plant on the site, which is expected to become operational in 2012, and sell electricity under a new PPA which we signed with Nevada Power Company (a subsidiary of NV Energy, Inc).


	•	In January 2010, we were awarded a geothermal exploration concession in Chile. The concession is on approximately 26,000 acres located to the north of the San Pablo/San Pedro twin volcanic complex in northern Chile and is close to access roads and to copper mines that could be potential users of the electricity. We plan to engage in preliminary testing and studies to assess the feasibility of the site for commercial development in accordance with the milestones set forth in the concession.

	•	In January 2010, we sold our interest in GDL for NZ$3.5 million (approximately US$2.6 million), and we were repaid a loan we made to GDL with an outstanding balance of NZ$24.3 million (approximately US$18.0 million).

	•	In December 2009, the PUCN approved certain amendments to certain of our PPAs for our power plants in Nevada that, among other things, removed partially the provisions for us to pay liquidated damages if certain minimum performance or availability criteria were not met.

	•	On November 4, 2009, we signed a 20-year PPA with Nevada Power Company for a 30 MW power plant for the McGinness Hills project in Nevada. The PPA is still subject to various approvals, including PUCN approval.

	•	In November 2009, we entered into a loan agreement for $50.0 million with a commercial bank. The loan matures on November 10, 2014 and is payable in 10 semi-annual installments commencing on May 10, 2010. The loan bears interest at 6-month LIBOR plus 3.25%.

	•	In October 2009, Ormat Nevada was awarded $13.7 million in grants under the DOE’s Innovative Exploration and Drilling Projects program for three of its projects: Maui, Glass Buttes, and Wister. The total amount of the grants accounts for approximately 50% of the total exploration budget of these projects. Ormat Nevada will use a combination of technologies to locate fault zones within geothermal reservoirs.

	•	On October 30, 2009, Ormat Nevada acquired Lehman-OPC LLC’s 30% interest in the Class B membership units of OPC, pursuant to a right of first offer for a price of $18.5 million. The repurchase of these interests at a discount resulted in a pre-tax gain of $13.3 million in the fourth quarter of 2009.

	•	In October 2009, Ormat Systems signed a joint venture agreement with Sunday Energy, a private company incorporated under the laws of Israel, to develop, construct and operate solar PV energy systems in Israel with a total capacity of 36 MW. Sunday will contribute the rights to all of its property required to develop solar energy systems above 1 MW to SPEs. Ormat Systems will own 70% of each SPE. Ormat Systems and Sunday will act, jointly, as the EPC contractor and the operator of each project in accordance with each company’s share in the SPEs. The electricity generated from the projects will be sold to Israel Electric Corporation Ltd. under a 20-year long-term PPA. The expected aggregate annual revenue from these agreements across all SPEs is approximately $30 million. The SPEs expect to finance their capital expenditure with 80% non-recourse third-party project financing debt.

	•	In July 2009, we entered into a 6-year loan agreement and an 8-year loan agreement for $20.0 million each with two separate groups of institutional investors. The 6-year loan matures on July 16, 2015, is payable in 12 semi-annual installments commencing January 16, 2010, and bears annual interest of 6.5%. The 8-year loan 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%.

	•	In May 2009, Ortitlan entered into a project financing loan of $42.0 million to refinance its investment in the 20.5 MW Amatitlan geothermal power plant. The loan was provided by TCW Global Project Fund II, Ltd.

	•	In the second quarter of 2009, we completed construction of a new 75,000 square foot manufacturing facility, which we lease from our parent, adjacent to our existing facility in Yavne, Israel. The new facility will enable us to expand our manufacturing capabilities.

	•	In March 2009, we declared commercial operation of the Peetz REG power plant that converts recovered waste heat from the exhaust of an existing gas turbine at a compressor station located along a natural gas pipeline near Denver, Colorado. The electricity produced by the power plant is sold under a 20-year PPA to Highline Electric Association Inc., a consumer-owned cooperative in Colorado and Nebraska.

Operations of our Power Generation 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 power plants, with the exception of the Puna power plant, 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 Nevada. These activities generally involve:


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

	•	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.

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

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

	•	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, creating access roads to drilling locations and related activities, as described under “Exploratory Drilling” below.

	•	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 under “Drilling” below. Drilling a full-size well is the point at which we consider a site moves from exploration to construction.

It normally takes us one to two 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.

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


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

	•	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.

	•	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.

	•	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 $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 Acquisition.

Land Acquisition. For domestic power plants, we either lease or own the sites on which our power plants are located. In 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. This documentation will usually give 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 under the heading “Description of Our Leases and Lands”.

For most of our current exploration sites in Nevada, 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. There is a summary of our typical lease terms under the heading “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. After obtaining drilling permits, we generally drill temperature gradient holes and/or slim holes using either our own drilling equipment or outside contractors. However, exploration of some geothermal resources can require drilling a full-size well, particularly where the resource is deep underground. If the slim hole is “dry”, it may be capped and the area reclaimed if we conclude that the geothermal resource will not

support a commercially viable power project. 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 reinjection of geothermal fluids (Production Well).

	•	Used as an observation well to monitor and define the geothermal resource.

The costs we incur for exploratory drilling vary from site to site based on various factors, including market demand for drilling contractors and equipment (which may be affected by on-shore oil and gas exploration activities, etc.), 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 approximately $5 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. In each case, this re-assessment is based on information available at that time. Among other things, we consider the following factors:


	•	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.

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

	•	Anticipated costs associated with further exploration activities.

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

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

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

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


	•	Drilling Production Wells.

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

	•	Obtaining any required permits.

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

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

It generally takes approximately two years from the time we drill a Production Well until the power plant becomes operational.

Drilling Production Wells. As noted above, we consider drilling the first Production Well as the beginning of our construction phase for a power plant. 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. In some cases we use outside contractors, generally firms that service the on-shore oil and gas industry.

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. On average, however, our costs for each Production Well range from $3 million to $5 million.

Design. We use our own employees to design the well field and the power plant, including equipment that we manufacture. 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 the heading “Environmental Permits”.

Manufacturing. Generally, we manufacture most of the power generating unit equipment we use at our power plants. Multiple sources of supply are 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, 2009, two sites moved from the exploration stage into construction, compared to one site during the year ended December 31, 2008. For 2009, these sites were Carson Lake, where a full-sized Production Well was drilled, and McGinness Hills. For 2008, this site was Jersey Valley. During the years ended December 31, 2008 and 2009, we discontinued exploration activities at two sites and one site, respectively, after drilling slim holes and concluding that the geothermal resource at those sites would not support commercially viable power plants at this time. Those sites are Buffalo Valley, Grass Valley and Rock Hills, all in northern Nevada. The costs associated with exploration activities at those sites were expensed during the years ended December 31, 2008 and 2009, respectively (see “Write-off of Unsuccessful Exploration Activities” under Item 7 — “Management Discussion and Analysis of Financial Condition and Results of Operations”). Six new sites were added to our exploration activities in 2009, compared with five sites that were added to our exploration activities in 2008.

How We Operate and Maintain Our Power Plants. We usually employ one of our subsidiaries (Ormat Nevada, for our domestic power plants) to act as operator of our power plants pursuant to the terms of an operation and maintenance agreement. 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 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 at our power plants.

How We Sell Electricity. In the United States, 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. A power plant’s revenues under a PPA used to consist of two payments — energy payments and capacity payments, however 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, such as us) 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 a financing structure 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.

For the next few years we expect to qualify for non-recourse or limited recourse debt financings under the DOE loan guaranty program under the ARRA.

The continuing effects of the economic crisis of 2009 could adversely affect our ability to obtain the kind of financing arrangements we have used in the past, and even if those arrangements are still available, the pricing and other terms of such arrangements may not be as favorable to us as in the past.

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 the heading “Insurance”. To date, our political risk insurance contracts are with 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% to 90% of our revenue loss derived 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 398,300 acres of federal, state, and private land in California, Nevada, Utah, Alaska, Hawaii, Oregon, and Idaho. The approximate breakdown between federal, state, and private leases is as follows:


	•	81% are leases with the U.S. government, acting through the BLM;

	•	10% are leases with various states, none of which is currently material; and

	•	9% are leases with private landowners and/or leaseholders.

Each of the leases within each of the categories has standard terms and requirements, as summarized below.

We own approximately 5,400 acres of land in Nevada and California.

Internationally, our land position includes approximately 27,220 acres.

Bureau of Land Management 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 communitization 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 1-2.5% 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% 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 reinject 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.

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		24 MW

Number of Power Plants		2 (Brady and Desert Peak 2 power plants)

Technology		The Brady complex utilizes binary and flash systems. The complex uses air and water cooling systems.

Subsurface Improvements		12 production wells and 6 injection wells connected to the plants through a gathering system.


Material Equipment		Three OEC units and three steam turbines along with 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 of mainly 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 284 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.

Temperature Cooling		Approximately 4 degrees Fahrenheit per year was observed during the past 15 years of production. The temperature decline at Desert Peak is less than 1 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.

Power Contract Expiration Date		Brady power plant — 2022. Desert Peak 2 power plant — 2027.

Financing		OFC Senior Secured Notes (Brady) and OPC Transaction (Desert Peak 2).

*Heber Complex*

Location		Heber, Imperial County, California

Generating Capacity		92 MW

Number of Power Plants		5 (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 cooling system.

Subsurface Improvements		29 production wells and 34 injection wells connected to the plants through a gathering system.

Material Equipment		17 OEC units and 1 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 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 350 degrees Fahrenheit. The resource supplying the pumped Heber 2 wells averages 325 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 H1 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.

Temperature Cooling		1 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		2 PPAs with Southern California Edison and 1 with SCPPA (Heber South plant).

Power Contract 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 Heber 1 and 2 PPAs.

Financing		OrCal Senior Secured Notes


*Mammoth Complex*

Location		Mammoth Lakes, California

Generating Capacity		29 MW (out of which our ownership is 50)%

Number of Power Plants		3 (G-1, G-2, and G-3)

Technology		The Mammoth complex utilizes binary systems. The complex uses an air cooling system.

Subsurface Improvements		9 production wells and 5 injection wells connected to the plants through a gathering system.

Material Equipment		8 Rotoflow expanders together with the Balance of Plant equipment.

Age		The G-1 plant commenced commercial operations in 1984 and G2 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 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 340 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 (> 3,500 feet) along faults and fracture zones from northwest to southeast east into the field area.

		The produced fluid has no scaling potential.

Temperature Cooling		1 degree Fahrenheit per year was observed during the past 20 years of production.

Power Purchaser		Southern California Edison

Power Contract Expiration Date		G-1 — 2014, G2, and G-3 — 2020

Financing		OFC Senior Secured Notes

*North Brawley Power Plant*

Location		Imperial County, California

Generating Capacity		50 MW (See supplemental information below)

Number of Power Plants		1

Technology		Binary system, the plant uses a water cooling system.


Subsurface Improvements		15 production wells and 15 injection wells are currently connected to the plant through a gathering system.

Material Equipment		5 OEC units together with the Balance of Plant Equipment.

Age		The power plant was placed in service on January 15, 2010.

Land and Mineral Rights		The total North Brawley area is comprised of private leases. The leases are held by production. The scheduled expiration dates for all of these leases are after the end of the expected useful life of the power plants.

		The plant’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.

Resource Information		North Brawley production is from deltaic and marine sedimentary sands and sandstones deposited in the subsiding Salton Trough of the Imperial Valley. The total thickness of these sediments is over 15,000 feet in the Brawley area based on seismic refraction surveys. The shallow production reservoir (1,500 — 4,500 feet) being developed has matrix permeability and is conductively heated from the underlying fractured reservoir which convectively circulates fluid magmatically heated by the deep basement rocks. Temperatures in the current producing reservoir range from 300 to 380 degrees Fahrenheit (335 degrees Fahrenheit average). Produced fluid salinity ranges from 20,000 to 50,000 ppm, and modest scaling and corrosion potential is chemically inhibited. The deeper fractured reservoir fluids exceed 525 degrees Fahrenheit, but are hypersaline and are not yet developed because of severe scaling and corrosion potential. The deep reservoir is not dedicated to the North Brawley power plant.

		The resource temperature is an average of 335 degrees Fahrenheit.

Sources of Makeup Water		Water is provided by IID.

Power Purchaser		Southern California Edison

Power Contract Expiration Date		2030

Financing		Corporate funds

Supplemental Information		On January 15, 2010, the power plant was placed in service and it is currently generating at stable level of 17 MW.

		While we believe that the power plant’s reservoir has sufficient flow to support the 50 MW output, the re-injection of the geothermal fluid has been a challenge due to the existence of an exceptional amount of sand in the geothermal fluid.


		We have made substantial progress in our ability to manage the large quantities of sand in the reservoir by installing certain temporary measures for handling solids. As a result, we are able to maintain a stable generation level of 17 MW, while awaiting the arrival of what is expected to be permanent equipment for the solids handling. The permanent equipment is expected to provide better efficiency as well as a lower operating cost for the facility.

		However, it appears that even with the solids in check, the injection capacity of some of the wells is disappointing and we are evaluating how to gradually bring the injection capability to its design capacity.

		We plan to request the power purchaser to agree to an extension of the firm operation date to the end of the year. This would give us more time to bring the power plant’s generation to its full design capacity of 50 MW.

		We have temporarily deferred submitting an application for the ITC cash grant for the project. The cash grant is expected to be more than $100 million.

		The power plant currently has an interim transmission agreement with IID. A transmission study expected to be released shortly will allow IID to enter into a permanent transmission agreement.

*OREG 1 Power Plant*

Location		Gas compressor stations along natural gas pipeline in North and South Dakota.

Generating Capacity		22 MW

Number of Units		4

Technology		The OREG 1 power plant utilizes our OEC units. The plant uses air cooled units.

Material Equipment		4 WHOH and 4 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

Power Contract 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		4

Technology		The OREG 2 power plant utilizes our OEC units. The plants use air cooled units.


Material Equipment		4 WHOH and 4 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

Power Contract Expiration Date		2034

Financing		Corporate funds

*Ormesa Complex*

Location		East Mesa, Imperial County, California

Generating Capacity		57 MW

Number of Power Plants		4 (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		34 production wells and 50 injection wells connected to the plants through a gathering system.

Material Equipment		32 OEC units and 2 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 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 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 307 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.


Temperature Cooling		1 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.

Power Contract Expiration Date		2018

Financing		OFC Senior Secured Notes

*Peetz Power Plant*

Location		Gas compressor stations along natural gas pipeline in Denver, Colorado.

Generating Capacity		3.5 MW

Number of Units		1

Technology		The Peetz power plant utilizes our OEC units. The plant uses an air cooled unit.

Material Equipment		2 WHOH and 1 OEC unit together with the Balance of Plant equipment.

Age		The Peetz 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

Power Contract Expiration Date		2029

Financing		Corporate funds

*Puna Power Plant*

Location		Puna district, Big Island, Hawaii

Generating Capacity		30 MW (See supplemental information below)

Number of Power Plants		1

Technology		The Puna plant utilizes an Ormat geothermal combined cycle system. The plant uses an air cooling system.

Subsurface Improvements		5 production wells and 3 injection wells connected to the plants through a gathering system.

Material Equipment		10 OEC units consisting of 10 binary turbines, 10 steam turbines along with the Balance of Plant equipment.

Age		The Puna plant commenced commercial operations in 1993.

Land and Mineral Rights		The Puna area is comprised of private leases. The private lease is between PGV and KPL and it expires in 2046. PGV pays annual rental payment to KPL, which is adjusted every 5 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 KPL, and KPL 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.

Temperature Cooling		The resource temperature is stable.

Power Purchaser		Two PPAs with HELCO

Power Contract Expiration Date		December 31, 2027

Financing		Operating Lease

Supplemental Information		The power plant is currently operating at approximately 17 MW as a result of a decline of the steam supply to the power plant.

		Our analysis determined that the decline is not related to the reservoir parameters. We believe the issue is a wellbore restriction that reduces the flow from the existing wells to the power plant. We are in the process of implementing a repair through a chemical or mechanical cleaning of the wells. We started the drilling of a new production well to increase the capacity of the power plant. Drilling the new well and connecting it to the power plant is expected to be completed by the end of the second quarter of 2010. We believe this should enable the power plant to generate at full capacity and will support the additional 8 MW project which is under construction. The estimated cost for the new well is approximately $11 million.

		We are currently negotiating with HELCO a fixed energy rate that would apply to any energy generated and sold above 25 MW.

*Steamboat Complex*

Location		Steamboat, Washoe County, Nevada

Generating Capacity		85 MW

Number of Power Plants		7 (Steamboat 1A, Steamboat 2/3, Burdette, Steamboat Hills, Galena 2 and Galena 3).

Technology		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 8 injection wells connected to the plants through a gathering system.

Material 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 2/3 were replaced with four turbines manufactured by us and 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 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 300 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 ft below the surface. Horizontal zones of permeability permit the hot water to flow eastward in an out-flow plume.

		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.

Temperature Cooling		2 degrees Fahrenheit per year was observed during the past 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 2/3, Burdette, Steamboat Hills, and Galena 3) and Nevada Power Company (for Galena 2).

Power Contract Expiration Date		Steamboat 1A — 2018, Steamboat 2/3 — 2022, Burdette — 2026, Steamboat Hills — 2018, Galena 3 — 2028, and Galena 2 — 2027.

Financing		OPC Transaction (Steamboat Hills, Galena 2, and Galena 3) and OFC Senior Secured Notes (Steamboat 1A, Steamboat 2/3, and Burdette).

Foreign Power Plants

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



*Amatitlan Power Plant (Guatemala)*

Location		Amatitlan, Guatemala

Generating Capacity		20 MW

Number of Power Plants		1

Technology		Binary system and a small back pressure steam turbine (1MW). The plant is air cooled.

Subsurface Improvements		5 production wells and 2 injection wells connected to the plants through a gathering system.

Material Equipment		1 steam turbine and 2 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% the of 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 530 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.

Temperature 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 Purchasers		INDE and another local purchaser.

Power Contract Expiration Date		Contract 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 CO ₂ per year. The power plant has a long-term contract to sell all of its emission reduction credits to a European buyer.


*Momotombo Power Plant (Nicaragua)*

Location		Momotombo, Nicaragua

Generating Capacity		26 MW

Number of Power Plants		1

Technology		Single flash and binary systems. The plant uses air and water cooling systems.

Subsurface Improvements		10 production wells and 7 injection wells connected to the plants through a gathering system.

Material Equipment		1 steam turbine and 1 OEC unit together with the Balance of Plant equipment.

Age		The plant commenced commercial operation in 1983 and was already in existence when we signed the concession agreement in 1999.

Land and Mineral Rights		The total Momotombo area is under a concession agreement which expires in 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 470 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.

Temperature Cooling		Approximately 3.5 degrees Fahrenheit per year was observed during the past 10 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

Power Contract Expiration Date		2014

Financing		Project finance — Bank Hapoalim B.M. The loan will be fully paid off in March 2010.

*Olkaria III Complex (Kenya)*

Location		Naivasha, Kenya

Generating Capacity		48 MW

Number of Power Plants		2 (Olkaria III phase 1 and Olkaria III phase II).

Technology		Binary system. The plants are air cooled.


Subsurface Improvements		9 production wells and 3 injection wells connected to the plants through a gathering system.

Material Equipment		6 OEC units together with the Balance of Plant Equipment.

Age		Phase I plant commenced commercial operation in 2000 and was incorporated into the phase II plant in January 2009.

Land and Mineral Rights		The total Olkaria III area is comprised of government leases. A license granted by the Kenyan government provides exclusive rights of use and possession of the relevant geothermal resources for an initial period of 30 years, expiring in 2029, which initial period may be extended for two additional five-year terms. The Kenyan Minister of Energy has the right to terminate or revoke the license in the event work in or under the license area stops during a period of six months, or 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 220kV 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 through low permeability at depth to a high productivity two phase region from 3,280 to 4,270 feet above sea level.

Temperature 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

Power Contract Expiration Date		2029

Financing		Senior secured project finance loan from a group of European DFI

Supplemental Information		We recently signed a letter of intent with KPLC with a view to expansion of the Olkaria III Complex within the framework of the existing PPA. See “Projects under Development and Future Projects — Olkaria III Phase 3 (Kenya)”.

*Zunil Power Plant (Guatemala)*

Location		Zunil, Guatemala

Generating Capacity		24 MW

Number of Power Plants		1

Technology		Binary system. The plant is air cooled.


Material Equipment		7 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 the company.

		The geothermal wells and resource are owned by INDE.

		Our produced power is sold at our fence; power transmission lines are owned and operated by INDE.

Access to Property		Direct access to public roads.

Power Purchaser		INDE

Power Contract Expiration Date		2019

Financing		Senior secured project loan from IFC and CDC

Supplemental Information		The energy output of the power plant is sold, until the end of 2011, under a “take or pay” arrangement, under which the revenues are calculated based on 24 MW capacity unrelated to the actual performance of the reservoir (currently 14 MW). From the beginning of 2012, the energy revenues will be paid based on the actual generation of the power plant. In 2009, the energy revenues were approximately 27% 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. Based on our current construction schedule, we have new generating capacity of approximately 125 MW under construction in California, Nevada, Minnesota, and Hawaii.

The following is a description of the projects currently undergoing construction:



*Carson Lake Project (U.S.)*

Location		Churchill County, Nevada

Projected Generating Capacity		20 MW

Projected Technology		Binary system. The plant will be air cooled.

Subsurface Improvements		Awaiting drilling permits.

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 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 in “Description of Our Leases and Lands”.

Resource Information		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 in leases from BLM.

Power Purchaser		Nevada Power Company

Power Contract Expiration Date		20 years after date of commercial operation.

Financing		Corporate funds.

Supplemental Information		Commercial operation of the power plant is expected in 2013.

		Our initial joint venture with Nevada Power Company for this project contemplated a larger project. We are in preliminary discussions to address the implications of a smaller project.

*East Brawley Project (U.S.)*

Location		Imperial County, California

Projected Generating Capacity		30 MW

Projected Technology		Binary system. The plant will be water cooled.

Subsurface Improvements		In process.

Material Equipment		Drilling equipment for wells.

Condition		Equipment manufacturing is in process.

		The project is still awaiting the required construction permits.

Land and Mineral Rights		The East Brawley area is comprised of mainly private leases, on which annual rental payments are paid, as described under “Description of Our Leases and Lands.”

		Unless steam is produced in commercial quantities, the primary term for these leases will expire on various dates commencing in June 2012.

Resource Information		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 leases.

Power Purchaser		We are negotiating a PPA with Southern California Edison that was allocated from the Wister project.

Power Contract Expiration Date		20 years from commercial operation.

Financing		Corporate funds

Supplemental Information		Based on the assumption that the permit to construct will be obtained in the third quarter of 2010 commercial operation of the power plant is expected in 2012. The project is eligible for financing under section 1703 of the DOE loan guaranty program.


*GRE Project (U.S.)*

Location		Gas compressor stations along Northern Boarder natural gas pipeline in Martin County, Minnesota.

Generating Capacity		5.5 MW

Number of Units		1

Technology		Binary system. The plant will use an air cooled unit.

Material Equipment		One WHOH and one OEC unit along with the Balance of Plant Equipment.

Land		Easement from NBPL

Access to Property		Direct access to the plant from public roads

Power Purchaser		Great River Energy

Power Contract Expiration Date		2029

Financing		Corporate funds

Supplemental Information		Plant interconnection to the utility grid line is expected to take place in the spring of 2010. Commercial operation will commence shortly thereafter.

*Jersey Valley Project (U.S.)*

Location		Pershing County, Nevada

Projected Generating Capacity		15 MW

Projected Technology		Binary system. The plant will use hybrid water and air cooled units.

Subsurface Improvements		In process

Condition		Field development for phase 1 completed. Power generating equipment is in production. Engineering in progress. Construction permit application not yet received.

Land and Mineral Rights		The Jersey Valley area is comprised of BLM leases.

		The leases are currently held by the payment of annual rental payments, as described 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, 2012. The project’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”.

Resource Information		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 leased property and access across leased property under surface rights granted in leases from BLM.

Power Purchaser		Nevada Power Company

Power Contract Expiration Date		20 years after date of commercial operation.


Financing		Corporate funds

		We are discussing a possible DOE-guaranteed financing with an institutional investor.

Supplemental Information		Commercial operation of the power plant is expected at the end of 2010.

*McGinness Hills Project (U.S.)*

Location		Lander County, Nevada

Projected Generating Capacity		30 MW

Projected Technology		Binary system. The plant will use hybrid water and air cooled units.

Subsurface Improvements		1 production well completed and tested.

Material Equipment		Drilling equipment for wells.

Condition		Basic well field site preparation has been completed. Permits to drill have been obtained. One production well was drilled. Drilling for an additional well has begun. Engineering of the power plant is in process. Application for construction permits has not been completed yet. Long lead items are on order or in production.

Land and Mineral Rights		The McGinness Hills area is comprised of BLM leases.

		The leases are currently held by the payment of annual rental payments, as described 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 in “Description of Our Leases and Lands”.

Resource Information		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 in leases from BLM.

Power Purchaser		Nevada Power Company

Power Contract Expiration Date		20 years after date of commercial operation.

Financing		Corporate funds

		We are discussing a possible DOE-guaranteed financing with an institutional investor.

Supplemental Information		Commercial operation of the power plant is expected in 2012.

*Puna Power Plant (U.S.)*

Location		Puna district, Big Island, Hawaii

Projected Generating Capacity		Additional 8 MW to the Puna power plant.

Projected Technology		Binary system. The plant will be air cooled.


Subsurface Improvements		In process

Material Equipment		Drilling equipment for wells and Balance of Plant equipment.

Condition		Permits to start construction have been obtained and site construction has begun.

		Equipment manufacturing was completed.

Land and Mineral Rights		The total Puna area, including the existing power plant, is comprised of private leases. See further description under Puna existing power plant above.

Resource Information		See description of our Puna power plant above.

Access to Property		See description of our Puna power plant above.

Power Purchaser		Negotiations of a PPA are underway with HELCO

Power Contract Expiration Date		Expected to coincide with the PPA of the existing Puna power plant: December 2027.

Financing		Corporate funds

Supplemental Information		Commercial operation of the power plant is expected in 2010.

*Tuscarora Project (U.S.)*

Location		Elko County, Nevada

Projected Generating Capacity		16 MW (Phase I)

Projected Technology		Binary system. The plant is expected to use hybrid water and air cooled units.

Subsurface Improvements		One full-size production well completed.

Material Equipment		Drilling equipment for wells.

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 in “Description of Our Leases and Lands.”

		Unless steam is produced in commercial quantities, the primary term for these leases will expire commencing November 20, 2014.

		The project’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”.

Resource Information		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 in leases from BLM.

Power Purchaser		Nevada Power Company

Power Contract Expiration Date		20 years after date of commercial operation.


Financing		Corporate funds

		We are discussing a possible DOE-guaranteed financing with an institutional investor.

Supplemental Information		Commercial operation of the power plant is expected in 2012.

		The project was acquired in February 2010.

		Under the PPA, the off-taker will purchase up to approximately 40 MW of electricity from the project, which will be developed in stages with the first stage of approximately 16 MW. The PPA allows for adjustment of the supply amount after the first year of commercial operation. The PPA is subject to approval by the PUCN.

Projects under Exploration and Development and Future Projects

We also have other projects under various stages of development in the United States, Guatemala, Chile, 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 generation capacity. Upon completion of these projects, their combined generating capacity would be approximately 184 MW.

Mammoth Phase II (U.S.)

We are currently developing Phase II of the Mammoth complex located in Mammoth Lakes, California. We have a 50% ownership interest in the power plant and the other 50% is owned by an unrelated third party.

We were unable to finalize a PPA based on a proposal short-listed by Southern California Edison last year, and recently resubmitted a new proposal for this power plant. An interconnection study is under way. In addition, we are negotiating certain modifications to our joint venture agreement with our 50% partner in this project.

Assuming the successful resolution of the negotiations described above and that we obtain the permits required to commence construction without delays, we anticipate that commercial operation of a 25 MW power plant will occur in 2013.

Olkaria III Phase 3 (Kenya)

We are currently developing Phase 3 of the Olkaria III complex located in Naivasha, Kenya. We recently signed a letter of intent with the off-taker, KPLC, to expand the Olkaria III complex by up to 52 MW (from 48 MW to up to 100MW) within the framework of the existing PPA.

The expansion is to be developed in two phases. Phase I will be comprised of 36 MW within 3.5 years from finalizing the amendment to the existing PPA. An optional phase II may be comprised of up to 16 MW within 4.5 years from finalizing the amendment to the existing PPA. The amendment to the existing PPA is subject to applicable governmental approvals and the consent of the lenders that provided the financing to the existing power plant.

Solar PV Projects (Israel)

We are currently in the process of developing solar PV projects. The following are projects we plan to develop together with Sunday Energy under a joint venture agreement we signed in October 2009. Our ownership interest in these projects is 70%:


	•	A 2 MW project to be built on non-agricultural land located in the north of Israel and comprised of approximately 10 acres. The joint venture will own 50% of the project.

	•	Four 8 MW projects each to be built on agricultural land located in the south of Israel and comprised of approximately 480 acres.


	•	Two 8 MW projects and an additional 5 MW project to be built on non-agrarian land located in the south of Israel and comprised of approximately 80 acres.

Sarulla Project (Indonesia)

We are a member of a consortium which is in the process of developing a geothermal power project in Indonesia of approximately 340 MW. We own 12.75% of the Indonesian special purpose entity that will operate the project.

The project, located in Tapanuli Utara, North Sumatra, represents the largest single-contract geothermal power project to date, and reflects the large scale, high productivity and potential of Indonesian geothermal resources. The project will be owned and operated by the consortium members under the framework of a Joint Operating Contract with PT Pertamina Geothermal Energy, and is to be constructed in three phases over five years, with each phase utilizing Ormat’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 Sarulla consortium is in negotiations with the state power utility PLN (the off-taker) to adjust the tariff of the PPA, and to introduce other amendments to satisfy lenders’ requirements. The government has allowed PLN to make contract amendments, including to the tariff, for the Sarulla project and a state audit agency team shall review these contract amendments, which shall also require approval of the Ministry of Energy and Mineral Resources and Ministry of State Owned Enterprises. From past experience it is hard to estimate when these negotiations will be concluded. Construction is expected to start after the Sarulla Consortium obtains financing, a process which we expect to take approximately one year from completion of the PPA negotiations with PLN.

Wister Project (U.S.) (previously known as Imperial Valley)

We are currently developing the Wister project on private leases located in Imperial County, California.

We reallocated the signed PPA for this project (which contemplated a 30-100 MW power plant) to our East Brawley project in Imperial County, California. We intend to negotiate a new PPA for this project.

We secured what we believe to be the appropriate land position for the project. We currently expect the first phase of the project to be 30 MW and expect commercial operation of the first phase in 2012 or 2013.

The project received 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.

In addition to the geothermal projects listed above, we have various leases for geothermal resources, under which we have started exploration activity but we cannot yet determine their expected generating capacity. These geothermal resources are located in Nevada, California, Alaska, Hawaii, Oregon, and Utah in the U.S., and in Guatemala and Chile. These leases are comprised of approximately 290,000 acres, including the following:


Name of Project		Status

Nevada
Dead Horse Wells		Completed exploration studies and have started exploratory drilling at the site.
Dixie Meadows		Completed exploration studies and are awaiting permits to start exploratory drilling at the site.
Gabbs		Completed exploration studies and have started exploratory drilling at the site.
Humboldt House		Lease acquired but no further action has yet been taken.
Hyder Hot Springs		Lease acquired but no further action has yet been taken.
Leach Hot Springs		Completed exploration studies and are awaiting permits to start exploratory drilling at the site.
Seven Devils		Lease acquired but no further action has yet been taken.
Smith Creek		Started exploration studies.


Name of Project		Status

Tungsten Mountain		Acquired 400 acres in the project area, and we plan to start physical exploration work once we secure more acreage.
Wildhorse		Lease acquired but no further action has yet been taken.
California
East & North Brawley		Deep resource — lease acquired but no further action has yet been taken.
Truck Haven		Lease acquired but no further action has yet been taken.
Hawaii
Maui		Started exploration studies and a $4.9 million DOE exploration grant has been awarded.
Oregon
Glass Buttes — Mahogany		Started exploration studies and a $4.3 million DOE exploration grant has been awarded.
Glass Buttes — Midnight Point		Started exploration studies.
Alaska
Mount Spurr		Started exploration studies.
Utah
Drum Mountain		Started exploration studies.
Whirlwind Valley		Started exploration studies.
Drum Mountain Expansion		Lease acquired but no further action has yet been taken.
Guatemala
Amatitlan Phase II		Started exploration studies.
Tecumburu		Surface rights have been obtained but no further action has yet been taken.
Chile
San Pablo		Exploration concession has been approved but no further action has yet been taken.

In addition to the geothermal resources listed above, we have leases pending for approximately 16,500 acres.

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 at times supported by letters of credit. We have not received any claims under the performance guarantees to date.

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, such as our PPA with Great River Energy for power from our REG facility on the Northern Border natural gas pipeline.

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. The Neptune recovered energy project is an example of such a model. There, we installed one of our recovered energy-based generation units at Enterprise Product’s Neptune gas processing plant in Louisiana. The unit utilizes exhaust gas from two gas turbines at the plant and is providing electrical power that is consumed internally by the facility (although a portion of the generated electricity is also sold to the local electric utility).

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 climate conditions, whether hot or cold. 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. We also design and construct the REG units on a turnkey basis, and may provide a long-term agreement to supply non-routine maintenance for such units. Our customers are interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators, and companies engaged in the process industry.

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, from time to time, enter 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 $90.0 million as of February 28, 2010, which includes revenues for the period between January 1, 2010 and February 23, 2010, compared to $194.0 million as of February 24, 2009. The following is a breakdown of the Product Segment backlog:


					Sales
		Sales			Expected to
	Expected	Expected to			be Recognized		Expected Sales
	Completion	be Recognized			in the Years		Until the End
	of the Contract	in 2010			Following 2010		of the Contract
		(In millions)			(In millions)		(In millions)

Geothermal	2010-2011	$	40.4		$	3.8	$	44.2
Recovered Energy	2010		10.0			—		10.0
Remote Power Units	2010-2011		27.3	*		3.6		30.9
Other	2010		4.4			—		4.4

Total Product Backlog		$	82.1		$	7.4	$	89.5


*		Including $19.4 million, which will become effective upon receipt of a down payment from the customer.

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 and suppliers.

Electricity Segment

Our main competitors among geothermal power plant owners and developers in the United States are CalEnergy, Calpine, Terra-Gen Power LLC, ENEL SpA and other smaller-sized pure play developers such as U.S. Geothermal Inc., Nevada Geothermal Power Corp., Raser Technologies Inc., Sierra Geothermal Company, Magma Energy Inc., Ram Power Corp., and Vulcan Power. Some of these companies are also active outside of the United States. Other competitors outside of the United States, aside from these companies, include affiliates of Chevron Corporation, Energy Development Corporation in the Philippines, developers such as Star Energy and Medco Energi in Indonesia, Mighty River Power in New Zealand and Colbus S.A. in Chile. We may also face competition from national electric utilities or state-owned oil companies.

Our competitors among renewable energy providers include companies engaged in the power generation business from renewable energy sources other than geothermal energy, 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. However, current demand for renewable energy is large enough that this increased competition has not materially impacted our ability to obtain new PPAs. We cannot ascertain at this time whether the competition from wind and solar energy will have an impact on electricity prices for new renewable projects.

If our plans to become a developer of solar PV power plants succeed, we will be competing with many other developers in this market.

Product Segment

Our competitors among power plant equipment suppliers are divided into two groups: 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, Ansaldo Energia, 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, United Technologies Company, Mafi Trench, GE Rotoflow of the U.S., and Turboden s.r.l. of Italy, or systems integrators such as Turbine Air Systems and Geothermal Development Associates of the U.S.

In the REG business, our competitors are Siemens AG of Germany, as well as other manufacturers of conventional steam turbines. We believe that our REG system has technological and economical advantages over the Siemens/Kalina technology and, under certain conditions, conventional steam technology.

In the remote power unit business, we face competition from Global Thermoelectric, as well as from manufacturers of diesel generator sets.

None of our competitors compete with us both in the sale of electricity and in the product business.

Customers

Most of our revenues from the sale of electricity in the year ended December 31, 2009 were derived from fully-contracted energy and/or capacity payments under long-term PPAs with governmental and private utility companies. Southern California Edison, Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.), HELCO, and SCPPA accounted for 21.0%, 12.9%, 6.3% and 2.1% of revenues, respectively, for the year ended December 31, 2009. Based on publicly available information, as of December 31, 2009, 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 (Negative outlook)	Ratings Withdrawn
Sierra Pacific Power Company	BB (stable outlook)	Ratings Withdrawn
Nevada Power Company	BB (stable outlook)	Ba3 (stable outlook)
SCPPA	A (Negative outlook)	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 business are derived from contractors or owners or operators of power plants, process companies, and pipelines, none of which traditionally account for more than 10% of our product segment revenues. However, for the year ended December 31, 2009, Blue Mountain and Las Pailas accounted for more than 57% of our product segment revenues and 22% of our total 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.

Since 2005, we have increased the volume of work ordered from subcontractors for some of the manufacturing for our products components and for construction activities of our power plants, which allowed 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, 2009, we employed 1,090 employees, of which 472 were located in the United States, 468 were located in Israel and 150 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 Momotombo power plant’s employees) 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.

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, insurance for work-related accidents, procedures for dismissing employees, annual and other vacation, sick pay, 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 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 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 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 Multilateral Investment Guarantee Agency (a member of the World Bank Group), and from private sector providers, such as Zurich Re and other such companies. To date all of our political risk insurance contracts are with the Multilateral Investment Guarantee Agency and with Zurich Re. We have obtained such insurance for all of our foreign power plants. Such insurance policies generally cover, subject to the limitations and restrictions contained therein, 80% to 90% of our revenue loss 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 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 megawatts; (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.

PURPA exempts Qualifying Facilities from regulation under the PUHCA 2005 and exempts Qualifying Facilities from most provisions of the FPA and state laws relating to the financial, organization and rate regulation of electric utilities. In addition, FERC’s regulations promulgated 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”).

Following passage of the Energy Policy Act of 2005, FERC issued a final rule that requires small power Qualifying Facilities to obtain market-based rate authority pursuant to the FPA for sales of energy or capacity from 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 Qualifying Facilities that are larger than 20 MW in size that seek to engage in non-PURPA sales of power (i.e., power that is sold in a manner that is not pursuant to a pre-existing contract or state implementation of PURPA) to obtain market-based rate authority from FERC for these non-PURPA sales. 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, the Qualifying Facility will not be required to file for market based rates.

The Energy Policy Act of 2005 also allows FERC 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 issued a rule to implement these provisions of the Energy Policy Act of 2005. This rule gives utilities the right to apply to eliminate the mandatory purchase obligation. The rule also creates a rebuttable presumption that a utility provides nondiscriminatory access if it has an open access transmission tariff in compliance with FERC’s pro forma open access transmission tariff. Further, the rule provides a procedure for utilities that are not members of the four named regional transmission organizations to file to obtain relief from the mandatory purchase obligation on a service territory-wide basis, and establishes procedures for affected Qualifying Facilities to seek reinstatement of the purchase obligation. The rule protects 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.

In addition, the Energy Policy Act of 2005 eliminated the restriction on utility ownership of a Qualifying Facility. Prior to the Energy Policy Act of 2005, electric utilities or electric utility holding companies could not own more than a 50% equity interest in a Qualifying Facility. Under the Energy Policy Act of 2005, electric utilities or holding companies may own up to 100% of the equity interest in a Qualifying Facility.

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 an elimination of the mandatory-purchase obligation in their service territories. 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

The 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, 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. Qualifying Facilities are exempt from most 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 is terminated or otherwise expires, a 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 appropriate 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 utility commissions. Sierra Pacific Power Company and Nevada Power Company are regulated by the PUCN. Southern California Edison and a small portion of Sierra Pacific Power Company in the Lake Tahoe area are regulated by the California Public Utility Commission.

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 Hawaii Public Utilities Commission 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 reinject 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. 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 surface water discharges associated with construction activities. Each well requires a preconstruction air permit before it can be drilled. In addition, 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 power plants have been obtained. Although there are some environmental permits and approvals that will be required in the future, we believe that we will be able to obtain those environmental permits and approvals without material delay and without incurring additional material costs.

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 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 (which we lease), 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.

Kenya . Kenya’s Power Act restructured the electricity sector in the country. Among other things, the Power 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 transmission and distribution of electricity in the country. The Power Act permitted 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 two other IPPs in addition to our Olkaria III complex. The Power Act also created the Electricity Regulation Board, as an independent regulator for the electricity sector. KPLC’s retail electricity rates are subject to approval by the Electricity Regulation Board. The Power Act was repealed by the Energy Act, which came into effect on July 7, 2007. One of the main changes introduced by the Energy Act was the reconstitution of the Electricity Regulatory Board as the Energy Regulatory Commission, with an expanded mandate to regulate not just the electric power sector but the entire energy sector in Kenya. Further re-organization of KPLC has been made with the formation of a new company known as KETRACO to undertake power transmission. KPLC will continue to undertake power distribution. This re-organization is in accordance with the National Energy Policy (Sessional Paper No. 4 of 2004). No announcement has been made as to whether KPLC’s transmission assets will be transferred to KETRACO. Another highlight of the Sessional Paper was the establishment of the state owned GDC which has now been formed and is operational. GDC is charged with the responsibility of geothermal assessment, drilling of steam wells, and sale of steam to future IPPs and to KenGen for electricity generation.

The Electricity Industry Reform Act 1998 requires full ownership separation between electricity lines (distribution) businesses, and electricity generation and retail businesses. Since the introduction of the Electricity Industry Reform Act 1998, however, amendments have allowed lines businesses to own some generation and to sell the output from those generation plants directly to consumers.

Regulation of Solar PV in Israel

The PUA published on December 12, 2009 regulations for medium-size solar PV power systems that are larger than 50 KW. According to the regulations, the capacity of the installed solar power systems may not exceed the feasible connection to the distribution network.

The PUA approved a feed-in-tariff for medium-sized power systems. This incentive is available for up to 300 MW of medium-sized power systems initiated prior to an expiry date in 2017. Rates under the feed-in-tariff are guaranteed for 20 years.

The feed-in-tariff rates awarded to new projects are set based on the year in which the PUA approval of such projects is obtained, as shown in the table below. If the capacity cap in a certain year is met, projects in excess of the cap will be awarded the feed-in-tariff for the following year.


Year	Annual Cap		Cumulative Cap		Rate*
	In MW		In MW		(Cent/kWh)

2010-2011		50		50		39
2012		65		115		37
2013		85		200		35
2014-2017		100		300		34


*		Based on an exchange rate of the NIS/dollar as of December 31, 2009 ($1 = NIS 3.775)

The licensing process designed by the PUA includes several stages.

Developers that are interested in applying for a production license are required at the first stage to obtain a temporary license that will be given to candidates who can demonstrate they meet the following requirements:


	•	Proven land position: for private lands, a signed option agreement between the candidate and the land-rights owner. In case the land is owned by ILA, the candidate must have a signed agreement with the land-rights owner and in addition an ILA land-rights preference.

	•	Adequate financial resources: the candidate must demonstrate 20% equity of the normative cost to build a power plant, which is estimated by the PUA at $5 million per installed MW.

	•	Feasibility study completed by the Israel Electric Corp. Ltd. that demonstrates the power plant can connect to the grid in accordance with the capacity demand (this requirement is only valid for facilities with capacity higher than 630KVA which will be connected to the high voltage grid).

Appropriate experience and capabilities for design, construction and operation of solar PV power plants according to the power plant size declared in the temporary license.

A request that demonstrates compliance with the above requirements will be reviewed by PUA staff and will require the approval of the PUA plenum followed by the approval of the Israeli Ministry of National Infrastructures.

Upon the signature of the conditional license by the Ministry of National Infrastructures, the developer of a facility with a capacity higher than 1 MW must provide the PUA with a bank guarantee in an amount equal to $1.80 per installed KV. In the event the developer subsequently fails to not meet the milestones specified in the conditional license for financial closing, the PUA may draw 35% of the bank guarantee.

A developer that receives a temporary license will have 42 months to obtain all required permits to operate the power plant and attain a production license.

The PUA regulations outline the milestones that the developer must follow including a site-specific statutory planning route that will be determined by the National Planning Council of the Israeli Ministry of Interior.

Following the statutory approval, the developer will receive a provisional tariff approval valid for 90 days which ensures the developer’s place under the cap. During that period the developer must close the financing terms. Once the financing terms are finalized the provisional tariff approval will become permanent, the tariff will be secured for 20 years from commercial operation and the developer can commence the construction and installation of the power plant upon receipt of the production license.

In addition to statutory approval, for lands owned by the ILA, the developer must obtain the consent of the ILA to build the power plants and will need to meet further conditions that will be required based on the land determination.


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 61.6% of our total revenues for the year ended December 31, 2009 from the sale of electricity. The cost of operation and maintenance and the operating performance of our subsidiaries’ geothermal power and REG plants may be adversely affected by a variety of factors, including some that are discussed elsewhere in these risk factors and the following:


	•	regular and unexpected maintenance and replacement expenditures;


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

	•	labor disputes;

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

	•	continued availability of cooling water supply;

	•	catastrophic events such as fires, explosions, earthquakes, 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

	•	the aging of power plants 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 2008, we experienced protracted failures of two of the Steamboat 2/3 power plant’s turbines, which were not manufactured by us. We replaced the turbines and successfully upgraded the power plant. 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. For example, we may not find geothermal resources capable of supporting a commercially viable power plant at a number of exploration sites where we have conducted tests, acquired land rights, and drilled test wells. In certain respects, these uncertainties 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, all of which can increase our operating costs and capital expenditures or reduce the efficiency of our power plants. Prior to our acquisition of the Steamboat Hills power plant, one of the wells related to the power plant experienced an uncontrolled release. In addition, the high temperature and high pressure in the Puna power plant’s geothermal energy resource requires special reservoir management and monitoring. Further, since the commencement of their operations, several of our power plants have experienced geothermal resource cooling in the normal course of operations, such as in the Brady and Momotombo power plants. 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 heat content (the relevant composition of temperature and pressure) of the geothermal reservoir, the useful life (commercially exploitable life) of the reservoir and operational factors relating to the extraction of geothermal fluids. Our geothermal energy power plants may 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. In addition, we may fail to find commercially viable geothermal resources in the expected quantities and temperatures, which would adversely affect our development of geothermal power plants.

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, or 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 become a wasting asset, and may adversely affect our ability to generate power from the relevant geothermal power plant.

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

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

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

We are currently in the process of developing and constructing a number of new power plants. We are also currently examining the possibility of entering the solar energy sector of the renewable energy industry and have recently entered into a joint venture with a third party to develop solar PV power projects in Israel. 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 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 development or construction in the United States 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:


	•	unanticipated cost increases;

	•	shortages and inconsistent qualities of equipment, material and labor;

	•	work stoppages;

	•	inability to obtain permits and other regulatory matters;

	•	failure by key contractors and vendors to timely and properly perform;

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


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

Any one of which 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.

A global recession and continued credit constraints could adversely affect us.

Recent disruption in the global credit markets, failures or material business deterioration of investment banks, commercial banks, and other financial institutions and intermediaries in the United States and elsewhere around the world, and significant reductions in asset values across businesses, households and individuals, combined with other financial and economic indicators, have combined to indicate a global recession. If these conditions continue or worsen, they may result in reduced worldwide demand for energy and difficulties in obtaining financing, which may adversely affect both our Electricity and Product Segments. Among other things, we might face:


	•	potential adverse impacts on our ability to access credit and other financing sources (and the cost thereof) beyond the approved credit lines we have. This may impact our ability to finance future acquisitions or significant capital expenditures relating to new projects or refinancing existing power plants to recover our cash invested;

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

	•	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;

	•	potential declines in revenues from some of our existing geothermal power plants as a result of curtailed electricity demand and low oil and gas prices; and

	•	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 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.

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, 2009, we had approximately $634.0 million of total consolidated indebtedness (including indebtedness to our parent company in the amount of $9.6 million), of which approximately $400.4 million represented non-recourse debt 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 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 risks 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 $169.3 million for the year ended December 31, 2009, which represented 40.8% of our total revenues for such twelve-month period. 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 for 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:


	•	changes in government policies or personnel;

	•	changes in general economic conditions;

	•	restrictions on currency transfer or convertibility;

	•	changes in labor relations;

	•	political instability and civil unrest;

	•	changes in the local electricity market;

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

	•	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 the country suggests increased opposition to the presence of foreign investors generally, including in the electricity sector. In Kenya, the government is continuing to make an effort to deliver on campaign promises to reduce the price of electricity and is applying pressure on IPPs to lower their tariffs. In addition, further re-organization of KPLC has been made with the formation of a new company known as KETRACO to undertake power transmission. KPLC will continue to undertake power distribution. This re-organization is in accordance with the National Energy Policy (Sessional Paper No. 4 of 2004). No announcement has been made as to whether KPLC’s transmission assets will be transferred to KETRACO. Another highlight of the Sessional Paper was the establishment of the state owned GDC which has now been formed and is operational. GDC is charged with the responsibility of 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, Inc.) and HELCO have accounted for 21.0%, 12.9% and 6.3%, respectively, of our revenues for the year ended December 31, 2009. Neither we nor any of our affiliates makes any representations as to the financial condition or creditworthiness of any purchaser under a PPA, and nothing in this annual report should be construed as such a representation.

There is a risk that any one or more of the power purchasers may not fulfill their respective payment obligations under their PPAs. For example, as a result of the energy crisis in California in the early 2000s, Southern California Edison withheld payments it owed under various of its PPAs with a number of power generators (such as the Ormesa, Heber, and Mammoth power plants) payable for certain energy delivered between November 2000 and March 2001 under such PPAs until March 2002. 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 short run avoided costs in effect 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 Burdette, Desert Peak 2, Galena 2, Galena 3, Carson Lake, Jersey Valley, McGinness Hills, Tuscarrora and North Brawley PPAs, 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. Four of the nine PPAs were in commercial operation in 2009 and to date the shortfall amount has not been material. 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 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 short run avoided costs 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 the PPAs for our power plants in California, the price that Southern California Edison pays for energy is based upon its short run avoided costs, 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 has been fixed through April 2012 and thereafter will be based on Southern California Edison’s short run avoided costs, as determined by the California Public Utilities Commission. These short run avoided costs 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 short run avoided cost 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.

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.

In addition, pursuant to the FPA, FERC has exclusive rate-making jurisdiction over wholesale sales of electricity and transmission of public utilities 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. Qualifying Facilities are largely exempt from the FPA. 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 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 was also given 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 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 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, which currently are significant, may increase in the future and could materially and adversely affect our business, financial condition, future results and cash flow; any non-compliance with such laws or regulations may result in the imposition of liabilities which could materially and adversely affect our business, financial condition, future results and cash flow.

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. 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. In addition, 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. As of the date of this report, we have not yet obtained certain permits and government approvals required for the completion and successful operation of power plants under construction or enhancement. In addition, a nearby municipality has informed our Amatitlan power plant that an additional building permit should be obtained from such municipality before construction commences. 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. 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.

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:


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

	•	inability to retain key personnel of the acquired companies;

	•	risks associated with unanticipated events or liabilities; and

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

If any of our acquired companies suffers customer dissatisfaction or performance problems, the same 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 existence of a prolonged force majeure event or a forced outage affecting a power plant 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, our subsidiary that owns that power plant would be excused from its obligations under the relevant PPA. However, 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. Accordingly, our business, financial condition, future results and cash flows could be materially and adversely affected.

The existence of a force majeure event or a forced outage affecting 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.

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, 2009, from the power plants utilizing the IID transmission system, were approximately $95.7 million. The impact of such force majeure would depend on the duration thereof, with longer outages resulting in greater revenue loss.

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 may 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, the payment of royalties for timber and the imposition of certain restrictions on residential development on the leased land. 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 activities in the areas of our power plants, thereby affecting our ability to utilize access, inject and/or transport geothermal resources on or underneath the affected surface areas.

Current and future urbanizing activities and related residential, commercial and industrial development may encroach on or limit geothermal activities in the areas of our power plants, 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 Calexio. There has been ongoing underlying interest since the early 1990s to incorporate the community of Heber. While any incorporation process would likely take several years, if Heber were to be incorporated, the City of Heber could replace Imperial County as the governing land use authority, which, depending on its policies, could have a significant effect on land use and availability of geothermal resources.

Current and future development proposals within Imperial County and the City of Calexico, applications for annexations to the City of Calexico, and plans to expand public infrastructure may affect surface areas within the

Heber KGRA, thereby limiting our ability to utilize, access, inject and/or transport the geothermal resource on or underneath the affected surface area that is necessary for the operation of our Heber power plants, which could adversely affect our operations and reduce our revenues.

Current transportation 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 the extension of an interstate highway (to be named U.S. 580) by the Nevada Department of Transportation, 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, Dita Bronicki, Nadav Amir, 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, Dita Bronicki and Yoram Bronicki, such members of our senior management may terminate their employment agreements without cause and with notice periods ranging from 90 to 180 days. 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 parent company loans 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 parent company loans and limited- or non-recourse project finance debt or lease financing. 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. 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. 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, and solar PV cells. 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.

We have identified recovered energy-based power generation as a significant market opportunity for us. 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.

We are subject to risks associated with a changing economic and political environment, which may adversely affect our financial stability or the financial stability of our counterparties.

The risk of terrorist attacks in the United States or elsewhere continues to remain a potential source of disruption to the nation’s economy and financial markets in general. The availability and cost of capital for our business and that of our competitors has been adversely affected by the bankruptcy of Enron Corp. and events related to the California electric market crisis. Additionally, the recent rise in fuel costs may make it more expensive for our customers to operate their businesses. These events could constrain the capital available to our industry and could adversely affect our financial stability and the financial stability of our transaction counterparties.

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 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.

Operations in Israel accounted for approximately 29.6%, 28.6%, and 26.4% of our operating expenses in the years ended December 31, 2009, 2008 and 2007, respectively. 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.

Since October 2000, there has been a significant increase in violence, primarily in the West Bank and the Gaza Strip. As a result, negotiations between Israel and representatives of the Palestinian Authority 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. At the end of December 2008, Israel engaged in an armed conflict with Hamas lasting for over three weeks, 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. We could be adversely affected by hostilities involving Israel, 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.

Failure to comply with certain conditions and restrictions associated with tax benefits provided to Ormat Systems by the Government of Israel as an “approved enterprise” may require us to refund such tax benefits and pay future taxes in Israel at higher rates.

Our subsidiary, Ormat Systems Ltd., which we refer to as Ormat Systems, has received “Benefited Enterprise” status under Israel’s Law for Encouragement of Capital Investments, 1959, with respect to two of its investment programs. As a Benefited Enterprise, our subsidiary 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 is subject to a reduced Israeli income tax rate not exceeding 25% for an additional five years. Our subsidiary is 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 a reduced Israeli income tax rate not exceeding 25% for an additional five years. These benefits are subject to certain conditions, including among other things, a requirement that Ormat Systems comply with Israeli intellectual property law, that all transactions between Ormat Systems and our affiliates be at arms length, and that there will be no change in control of, on a cumulative basis, more than 49% of Ormat Systems’ capital stock (including by way of a public or private offering) without the prior written approval of the Income Tax Authorities. If Ormat Systems does not comply with these conditions, in whole or in part, it would be required to refund the amount of tax benefits (as adjusted by the Israeli consumer price index and for accrued interest) and would no longer benefit from the reduced Israeli tax rate, which could have an adverse effect on our business, financial condition, future results and cash flow. If Ormat Systems distributes dividends out of revenues derived during the tax exemption period from the benefited investment program, it will be subject, in the year in which such dividend is paid, to Israeli income tax on the distributed dividend.

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, any sublease for a period of more than five years may require the prior approval of the Israel Land Administration. As a result, the initial term of our sublease with Ormat Industries is for a period of four years and eleven months beginning on July 1, 2004, extendable to twenty-five years less one day (which includes the initial term). 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, such as the Mammoth complex, there may be certain additional restrictions on dividend distributions pursuant to our agreements with our 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.

Some 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.

Three of our seven directors are directors and/or officers of Ormat Industries, namely Lucien Bronicki, Dita Bronicki and Yoram Bronicki. In addition, four of our executive officers are also executive officers of Ormat Industries. Specifically, our Chairman, Director and Chief Technology Officer, Lucien Bronicki, is the Chairman of our parent; our Chief Executive Officer and Director, Dita Bronicki, is the Chief Executive Officer of our parent; 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 controlling stockholders may take actions that conflict with your interests.

Ormat Industries Ltd. holds approximately 56% of our common stock. Bronicki Investments Ltd. holds approximately 35.2% of the outstanding shares of common stock of Ormat Industries Ltd. as of February 28, 2010 (35.1% on a fully diluted basis). Bronicki Investments Ltd. is a privately held Israeli company and is controlled by Lucien and Dita Bronicki. Because of these holdings, our parent company will be able to exercise control over all matters requiring stockholder approval, including the election of directors, amendment of our certificate of incorporation and approval of significant corporate transactions, and they will have significant control over our management and policies. The directors elected by these stockholders will be able to significantly influence decisions affecting our capital structure. 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. For example, our controlling stockholders will be able to control the sale or other disposition of our product business to another entity or the transfer of such business outside of the State of Israel, as such action requires the affirmative vote of at least 75% of our outstanding shares.

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

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


	•	actual or anticipated fluctuations in our results of operations including as a result of seasonal variations in our electricity-based revenues;

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

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

	•	announcements of significant contracts by us or our competitors;

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

	•	loss of one or more of our significant customers;

	•	legislation;

	•	changes in market valuation or earnings of our competitors;

	•	the trading volume of our common stock; and

	•	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 Ltd., holds approximately 56% 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.

The SOX Act imposes significant regulatory, corporate and operational requirements on the Company. Failure to comply with such provisions may have significant adverse consequences to the Company.

As a public company, we are subject to the SOX Act. The SOX Act contains a variety of provisions affecting public companies, including but not limited to, corporate governance requirements, our relationship with our auditors, evaluation of our internal disclosure controls and procedures, and evaluation of our internal control over financial reporting. See Management’s Report on Internal Control over Financial Reporting and Item 9A. — “Controls and Procedures.”


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 (including approximately 75,000 square feet in a new specialized manufacturing building) 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 including the new facility 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 2009, other than as described below.

From time to time, we (including our subsidiaries) are a party to various other lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our (and their) 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, we accrue reserves in accordance with U.S. generally accepted accounting principles. We do not believe that any of these proceedings, individually or in the aggregate, would materially and adversely affect our business, financial condition, future results, or cash flow.

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 March 4, 2010, there were 16 record holders of the Company’s common stock. On March 4, 2010, our stock’s closing price as reported on the NYSE was $29.58 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.

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


	Dividend
Date Declared	Amount per Share		Record Date	Payment Date

February 26, 2008	$	0.05	March 14, 2008	March 27, 2008
May 6, 2008	$	0.05	May 20, 2008	May 27, 2008
August 5, 2008	$	0.05	August 19, 2008	August 29, 2008
November 5, 2008	$	0.05	November 19, 2008	December 1, 2008
February 24, 2009	$	0.07	March 16, 2009	March 26, 2009
May 8, 2009	$	0.06	May 20, 2009	May 27, 2009
August 5, 2009	$	0.06	August 18, 2009	August 27, 2009
November 4, 2009	$	0.06	November 18, 2009	December 1, 2009
February 23, 2010	$	0.12	March 16, 2010	March 25, 2010

High/Low Stock Prices:

Ormat Technologies, Inc. (ORA) — High and Low Prices for the years ended December 31, 2008 and 2009, and from January 1 until March 4, 2010:


																	January 1
	First		Second		Third		Fourth		First		Second		Third		Fourth		to
	Quarter		Quarter		Quarter		Quarter		Quarter		Quarter		Quarter		Quarter		March 4,
	2008		2008		2008		2008		2009		2009		2009		2009		2010

High:	$	56.12	$	54.94	$	50.43	$	35.00	$	35.88	$	41.77	$	42.68	$	44.13	$	38.00
Low:	$	39.79	$	45.15	$	36.33	$	22.85	$	22.84	$	26.85	$	33.99	$	35.70	$	28.79

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, 2009 for our common stock, compared to the Standard and Poor’s Composite 500 Index, and a peer group.

Comparison of Cumulative Returns For the Period November 11, 2004 through December 31, 2009


	11/11/2004		12/31/2004		12/31/2005		12/31/2006		12/31/2007		12/31/2008		12/31/2009
Ormat Technologies Inc	$	100	$	109	$	174	$	245	$	367	$	212	$	252
Standard & Poor’s Composite 500 Index	$	100	$	108	$	111	$	126	$	131	$	80	$	99
IPP Peers*	$	100	$	119	$	110	$	167	$	163	$	131	$	187
Renewable Peers*	$	100	$	126	$	202	$	170	$	327	$	102	$	101


*		IPP Peers are The AES Corporation, NRG Energy Inc., Calpine Corporation and International Power PLC. Renewable Energy (Renewable) Peers are Acciona S.A., Evergreen Solar Inc., Energy Conversion Devices Inc., Nevada Geothermal Power Corp., Raser Technologies Inc. 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”.

Recent Sales of Unregistered Securities and Use of Proceeds from Registered Securities

None.


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, 2009, 2008 and 2007 and as of December 31, 2009 and 2008 from our audited consolidated financial statements set forth in Part II Item 8 of this annual report. We have derived the selected consolidated financial data for the years ended December 31, 2006 and 2005, and as of December 31, 2007, 2006 and 2005 from our audited consolidated financial statements not included herein, after giving retroactive effect to the adoption of the new accounting guidance for noncontrolling interests in a subsidiary and for the deconsolidation of a subsidiary.

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 set forth in Item 8 of this annual report.


	Years Ended December 31,
	2009			2008 (As Restated ⁽²⁾ ) ⁽¹⁾			2007 ⁽¹⁾			2006 ⁽¹⁾			2005 ⁽¹⁾
				(In thousands, except per share data)

Statements of Operations Data:
Revenues:
Electricity	$	255,855		$	252,256		$	215,969		$	195,483		$	177,369
Product		159,389			92,577			79,950			73,454			60,623

Total revenues		415,244			344,833			295,919			268,937			237,992

Cost of revenues:
Electricity		180,156			170,053			148,698			124,356			103,615
Product		112,450			72,755			68,036			51,215			45,236

Total cost revenues		292,606			242,808			216,734			175,571			148,851

Gross margin:		122,638			102,025			79,185			93,366			89,141
Operating expenses:
Research and development expenses		10,502			4,595			3,663			2,983			3,036
Selling and marketing expenses		14,584			10,885			10,645			10,361			7,876
General and administrative expenses		26,412			25,938			21,416			18,094			14,320
Write-off of unsuccessful exploration activities		2,367			9,828			—			—			—

Operating income		68,773			50,779			43,461			61,928			63,909
Other income (expense):
Interest income		639			3,118			6,565			6,560			4,308
Interest expense, net		(16,241	)		(14,945	)		(29,745	)		(30,961	)		(55,317	)
Foreign currency translation and transaction gains (losses)		1,107			(7,721	)		(1,339	)		(704	)		(439	)
Impairment of auction rate securities		(279	)		(4,195	)		(2,020	)		—			—
Income attributable to sale of tax benefits		15,515			18,118			6,488			—			—
Gain from extinguishment of liability		13,348			—			—			—			—
Other non-operating income		479			771			890			694			512

Income before income taxes and equity in income of investees		83,341			45,925			24,300			37,517			12,973
Income tax provision		(16,924	)		(4,358	)		(1,822	)		(6,403	)		(4,690	)
Equity in income of investees, net		2,136			1,725			4,742			4,146			6,894

Net income		68,553			43,292			27,220			35,260			15,177
Net loss (income) attributable to noncontrolling interest		298			316			156			(813	)		—

Net income attributable to the Company’s stockholders	$	68,851		$	43,608		$	27,376		$	34,447		$	15,177


	Years Ended December 31,
	2009		2008 (As Restated ⁽²⁾ ) ⁽¹⁾		2007 ⁽¹⁾		2006 ⁽¹⁾		2005 ⁽¹⁾
			(In thousands, except per share data)

Earnings per share attributable to the Company’s stockholders:
Basic	$	1.52	$	0.99	$	0.71	$	1.00	$	0.48

Diluted	$	1.51	$	0.98	$	0.70	$	0.99	$	0.48

Weighted average number of shares used in computation of earnings per share attributable to the Company’s stockholders:
Basic		45,391		44,182		38,762		34,593		31,563

Diluted		45,533		44,298		38,880		34,707		31,609

Cash dividend per share declared during the year	$	0.25	$	0.20	$	0.22	$	0.15	$	0.12

Balance Sheet Data (at End of Year):
Cash and cash equivalents	$	46,307	$	34,393	$	47,227	$	20,254	$	26,976
Working capital		55,652		3,296		22,337		34,429		36,616
Property, plant and equipment, net (including construction-in process)		1,517,288		1,334,859		977,400		793,164		620,091
Total Assets		1,855,001		1,630,976		1,277,368		1,160,102		914,480
Long-term debt (including current portion)		624,442		386,635		322,472		372,009		365,539
Notes payable to Parent (including current portion)		9,600		26,200		57,847		140,153		171,805
Liability associated with sale of tax benefits		73,246		113,327		63,090		—		—
Equity		911,695		847,235		627,836		440,925		182,387


⁽¹⁾		We adopted the new accounting guidance for noncontrolling interests in a subsidiary on January 1, 2009. Under this guidance, noncontrolling interests are to be presented on the balance sheet as a component of equity. The adoption of this standard resulted in retrospective presentation changes to the statements of operations data for the years ended December 31, 2008, 2007, 2006 and 2005 and the balance sheet data as of the end of those years. The impact of adopting this standard is more fully described in Note 11 to our consolidated financial statements set forth in Item 8 of this annual report.

⁽²⁾		Restatement

		Through the third quarter of 2009, we accounted for exploration and development costs using an accounting method that is analogous to the full cost method used in the oil and gas industry. Under that method, we capitalized costs incurred in connection with the exploration and development of geothermal resources on an “area-of-interest” basis. Each area of interest included a number of potential projects in the state of Nevada that were planned to be operated together with the same operation and maintenance team. Impairment tests were performed on an area-of-interest basis rather than at a single site. Under this methodology, costs associated with projects that we have determined are not economically feasible remained capitalized as long as the area-of-interest was not subject to impairment.

		Following a periodic review performed by the SEC Staff, we concluded that this accounting treatment was inappropriate in certain respects and have restated the 2008 consolidated financial statements to write-off capitalized costs for projects we have determined are not economically feasible in the period such determination was made.

		The effect of the restatement on the statement of operations data for the year ended December 31, 2008 and on the balance sheet data as of the end of this year is as follows:

Statements of Operations Data for the Year Ended December 31, 2008:


							As Restated
							Before			Application
							Application of			of New
	As Originally			Restatement			New Accounting			Accounting
	Reported			Adjustment			Standard			Standard			As restated
	(Dollars in thousands)

Write-off of unsuccessful exploration activities	$	—		$	(9,828	)	$	(9,828	)	$	—		$	(9,828	)

Operating income		60,607			(9,828	)		50,779			—			50,779

Other income (expense):
Interest income		3,118			—			3,118			—			3,118
Interest expense, net		(7,677	)		—			(7,677	)		(7,268	)		(14,945	)
Foreign currency translation and transaction losses		(7,721	)		—			(7,721	)		—			(7,721	)
Income attributable to sale of tax benefits		—			—			—			18,118			18,118
Other non-operating expense, net		(3,424	)		—			(3,424	)		—			(3,424	)

Income before income taxes, minority interest, and equity in income of investees		44,903			(9,828	)		35,075			10,850			45,925
Income tax provision		(7,962	)		3,604			(4,358	)		—			(4,358	)
Minority interest		11,166			—			11,166			(11,166	)		—
Equity in income of investees, net		1,725			—			1,725			—			1,725

Net income		49,832			(6,224	)		43,608			(316	)		43,292
Net loss attributable to noncontrolling interest		—			—			—			316			316

Net income attributable to the Company’s stockholders	$	49,832		$	(6,224	)	$	43,608		$	—		$	43,608

Balance Sheet Data as of December 31, 2008:


						As Restated
						Before		Application
						Application of		of New
	As Originally		Restatement			New Accounting		Accounting
	Reported		Adjustment			Standard		Standard			As Restated
	(In thousands)

Assets
Property, plant and equipment (including construction-in-process)	$	1,344,687	$	(9,828	)	$	1,334,859	$	—		$	1,334,859
Deferred financing and lease costs, net		16,127		—			16,127		3,113			19,240

Total assets	$	1,637,691	$	(9,828	)	$	1,627,863	$	3,113		$	1,630,976

Liabilities and equity
Liability associated with sale of tax benefits	$	—	$	—		$	—	$	113,327		$	113,327
Deferred income taxes		33,231		(3,604	)		29,627		—			29,627

Total liabilities		674,018		(3,604	)		670,414		113,327			783,741

Minority interest		117,245		—			117,245		(117,245	)		—

Equity:
The Company’s stockholders’ equity:
Common stock		45		—			45		—			45
Additional paid-in capital		701,273		—			701,273		—			701,273
Retained earnings		144,465		(6,224	)		138,241		—			138,241
Accumulated other comprehensive income		645		—			645		—			645

		846,428		(6,224	)		840,204		—			840,204
Noncontrolling interest		—		—			—		7,031			7,031

Total equity		846,428		(6,224	)		840,204		7,031			847,235

Total liabilities and equity	$	1,637,691	$	(9,828	)	$	1,627,863	$	3,113		$	1,630,976


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 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.

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 two business segments, which we refer to as our Electricity Segment and Product Segment. In our Electricity 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 recently decided to expand 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. In our Product 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 power plants. 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. During the years ended December 31, 2009 and 2008, our consolidated U.S. and international power plants generated 3,360,676 MWh and 2,942,917 MWh, respectively.

For the year ended December 31, 2009, our Electricity Segment represented approximately 61.6% of our total revenues, while our Product Segment represented approximately 38.4% of our total revenues during such year. For the year ended December 31, 2008, our Electricity Segment represented approximately 73.2% of our total revenues, while our Product Segment represented approximately 26.8% of our total revenues during such year.

For the year ended December 31, 2009, our total revenues increased by 20.4% (from $344.8 million to $415.2 million) over the previous year. Revenues from the Electricity Segment increased by 1.4%, while revenues from the Product Segment increased by 72.2%.

For the year ended December 31, 2009, total Electricity Segment revenues from the sale of electricity by our consolidated power plants were $255.9 million, compared to $252.3 million for the year ended December 31, 2008. In addition, revenues from our 50% ownership of the Mammoth complex in the years ended December 31, 2009 and 2008 were $9.9 million and $9.6 million, respectively. This additional data is a Non-Generally Accepted Accounting Principles (Non-GAAP) financial measure as defined by the SEC. There is no comparable GAAP measure. Management believes that such Non-GAAP data is useful to the readers as it provides a more complete view on the scope of the activities of the power plants that we operate. Our investment in the Mammoth complex is accounted for in our consolidated financial statements under the equity method and the revenues are not included in our consolidated revenues for the years ended December 31, 2009 and 2008.

For the year ended December 31, 2009, revenues attributable to our Product Segment were $159.4 million, compared to $92.6 million during the year ended December 31, 2008, an increase of 72.2%. Most of the increase in revenues was derived from EPC contracts with third parties for the construction of three large binary geothermal projects, the Blue Mountain project in Nevada, the Centennial Binary Plant in New Zealand, and the Las Pailas project in Costa Rica.

Revenues from our Electricity Segment are relatively predictable, as they are derived from sales of electricity generated by our power plants pursuant to long-term PPAs. The price for electricity under all but one of our PPAs is effectively a fixed price at least through May 2012. The exception is the PPA of the Puna power plant. It has a monthly variable energy rate based on the local utility’s avoided costs, which is the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others. In the year ended December 31, 2009, the variable energy rate in the Puna power plant decreased significantly mainly as a result of lower oil prices, which in turn impacted the gross margin of our Electricity Segment. In the year ended December 31, 2009, approximately 86% of our electricity revenues were derived from contracts with fixed energy rates, and therefore most of our electricity revenues were not affected by the fluctuations in energy commodity prices. However, electricity revenues are subject to seasonal variations and can be affected by higher-than-average ambient temperatures, as described below under the heading “Seasonality”. 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, relevant technical and geological matters and other relevant 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, gross margin, 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 newly enacted legislative and regulatory requirements and incentives, such as state renewable portfolio standards and federal tax credits. The recently enacted ARRA further encourages the use of geothermal energy through production or investment tax credits as well as cash grants (which are discussed in more detail in the section entitled “Government Grants and Tax Benefits”). 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.

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 fully-contracted payments under long-term PPAs. We also intend to continue to pursue growth in our recovered energy business.

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:


	•	The global recession resulting from the recent disruption in the global credit markets, failures or material business deterioration of investment banks, commercial banks, and other financial institutions and intermediaries in the United States and elsewhere around the world, significant reductions in asset values across businesses, households and individuals, and the slowdown in manufacturing and other business activity has also resulted in reduced worldwide demand for energy. If these conditions continue or worsen, they may adversely affect both our Electricity and Product Segments. Among other things, we might face: (i) potential declines in revenues in our Product Segment due to reduced orders or other factors caused by economic challenges faced by our customers and prospective customers; (ii) potential declines in revenues from some of our existing geothermal power projects as a result of curtailed electricity demand and low oil and gas prices; and (iii) potential adverse impacts on our customers’ ability to pay, when due, amounts payable to us. In addition, we may experience related increases in our cost of capital associated with any increased working capital or borrowing needs we may have if our customers do not pay, or if we are unable 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.

	•	The worldwide credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. While we have sufficient financial resources to fund our projected activities for 2010, if these conditions continue or worsen, the cost of obtaining financing for our project needs may increase or such financing may not be available at all.

	•	Our primary focus continues to be the implementation of 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 year over year. We may also look at acquisition opportunities that may arise.


	•	In the United States, we expect to continue to benefit from the increasing demand for renewable energy. Thirty-five states and the District of Colombia, including California, Nevada and Hawaii (where we have been most active in geothermal development and in which all of our U.S. geothermal power plants are located) have RPS, renewable portfolio goals or other similar laws. These laws require that an increasing percentage of the electricity supplied by electric utility companies operating in such states be derived from renewable energy resources until certain pre-established goals are met. We expect that the additional demand for renewable energy from utilities in such states will outpace a possible reduction in general demand for energy due to the economic slow down and will continue to create opportunities for us to expand existing power plants and build new power plants.

	•	We expect that the increased awareness of climate change may result in significant changes in the business and regulatory environments, which may create business opportunities for us going forward. Although federal legislation addressing climate change appears likely, several states and regions are already addressing climate change. For example, the California Global Warming Solutions Act of 2006, which was signed into law in September 2006, regulates most sources of greenhouse gas emissions and aims to reduce greenhouse gas emissions to 1990 levels by 2020, representing an approximately 30% reduction in greenhouse gas emissions from projected 2020 levels or about 15% from 2008 levels. The California Air Resources Board is expected to put in place measures for implementing the Global Warming Solutions Act of 2006 by 2012. In September of 2006, California also passed Senate Bill 1368, which prohibits the state’s utilities from entering into long-term financial commitments for base-load generation with power plants that fail to meet a CO ₂ emission performance standard established by the California Energy Commission and the California Public Utilities Commission. California’s long-term climate change goals are reflected in Executive Order S-3-05, which requires a reduction in greenhouse gases to: (i) 2000 levels by 2010; (ii) 1990 levels by 2020; and (iii) 80% of 1990 levels by 2050. In addition to California, twenty-one other states have set greenhouse gas emissions targets (Arizona, Colorado, Connecticut, Florida, Hawaii, Illinois, Maine, Maryland, Massachusetts, Minnesota, Montana, New Hampshire, New Jersey, New Mexico, New York, Oregon, Rhode Island, Utah, Vermont, Virginia and Washington). Regional initiatives, such as the Western Climate Initiative (which includes seven U.S. states and four Canadian provinces) and the Midwest Greenhouse Gas Reduction Accord, are also being developed to reduce greenhouse gas emissions and develop trading systems for renewable energy credits. In September 2008, the first-in-the-nation auction of CO ₂ allowances was held under the RGGI, a regional cap-and-trade system, which includes ten Northeast and Mid-Atlantic States. Under RGGI, the ten participating states plan to stabilize power section carbon emissions at their capped level, and then reduce the cap by 10% at a rate of 2.5% each year between 2015 and 2018. In addition, thirty-five states and the District of Columbia have all adopted RPS, as discussed above. In November 2008, California, by Executive Order S-14-08, adopted a goal for all retailers of electricity to serve 33% of their load with renewable energy by 2020, and in September of 2009, Executive Order S-21-09 directed the California Air Resources Board to adopt regulations consistent with the 33% renewable energy target by July 31, 2010. Although it is currently difficult to quantify the direct economic benefit of these efforts to reduce greenhouse gas emissions, we believe they will prove advantageous to us.

	•	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. The current demand for renewable energy is large enough that this increased competition has not materially impacted our ability to obtain new PPAs. However, the increase in competition 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.


	•	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 lead to a reduction in prices that we are able to charge for our binary equipment, which in turn may impact our profitability.

	•	We also expect increased competition from new geothermal power developers which may impact the prices and availability of new leases for geothermal resources.

	•	While the current demand for renewable energy is large enough that increased competition has not impacted our ability to obtain new PPAs and new leases, increased competition in the power generation space may contribute to a reduction in electricity prices, and increased competition in geothermal leasing may contribute to an increase in lease costs.

	•	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 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 we face in connection with our growth expectations.

	•	As our power plants 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 such decrease in availability.

	•	Our foreign operations are subject to significant political, economic and financial risks, which vary by country. 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.

	•	On May 5, 2009, President Obama and the U.S. Treasury Department proposed changing certain of the U.S. tax rules for U.S. corporations doing business outside the United States. The proposed changes would limit the ability of U.S. corporations to deduct expenses attributable to offshore earnings, modify the foreign tax credit rules and further restrict the ability of U.S. corporations to transfer funds between foreign subsidiaries without triggering a requirement to pay U.S. income tax. Although the scope of the proposed changes is unclear, it is possible that these or other changes in the U.S. tax laws may increase our U.S. income tax liability and adversely affect our profitability.

	•	The Energy Policy Act of 2005 authorizes FERC to revise PURPA so as to terminate 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 contracts are long-term. FERC issued a final rule that makes it easier to eliminate the utilities’ purchase obligation in four regions of the country. None of those regions includes a state in which our current power plants operate. However, FERC has the authority under the Energy Policy Act of 2005 to act, on a case-by-case basis, to eliminate the mandatory purchase obligation in other regions. If the utilities in the regions in which our domestic power plants operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from us upon termination of the existing PPA, which could have an adverse effect on our revenues.

Revenues

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

Revenues attributable to our Electricity Segment are relatively predictable as they are derived from the sale of electricity from our power plants pursuant to long-term PPAs. However, such revenues are subject to seasonal variations, as more fully described below in the section entitled “Seasonality”. Electricity Segment revenues 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 levels and the potential forfeiture of payments if we fail to meet minimum target 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 short run avoided costs (the incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others). Our more recent PPAs provide generally for energy payments alone with an obligation to compensate the off-taker for its incremental costs as a result of shortfalls in our supply.

The prices paid for electricity pursuant to the PPA of the Puna power plant are tied to the price of oil. Accordingly, our revenues for that power plant, which accounted for approximately 6.3% and 16.7% of our total revenues for the years ended December 31, 2009 and 2008, respectively, may be volatile. The decrease in our revenues from the Puna power plant in the year ended December 31, 2009 is also attributable to the decrease in its electricity generation as more fully described under “Results of Operations” below.

Revenues attributable to our Product Segment are generally less predictable than revenues from our Electricity Segment. This is because larger customer orders for our products are typically a 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 long 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. As a result, 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, our revenues from our Product Segment fluctuate (and at times, extensively) from period to period. As discussed under “Trends and Uncertainties” above, we may experience declines in revenues in our Product Segment due to reduced orders or other factors caused by the global recession and economic challenges faced by our customers and prospective customers.

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,
	2009		2008		2007		2009			2008			2007

Revenues
Electricity	$	255,855	$	252,256	$	215,969		61.6	%		73.2	%		73.0	%
Product		159,389		92,577		79,950		38.4			26.8			27.0

Total	$	415,244	$	344,833	$	295,919		100.0	%		100.0	%		100.0	%

Geographical breakdown of revenues

For the years ended December 31, 2009, 2008 and 2007, 71.2%, 82.0% and 83.3%, respectively, of our revenues attributable to our Electricity Segment were generated in the United States.

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


	Revenues in Thousands						% of Revenues for Period Indicated
	Year Ended December 31,						Year Ended December 31,
	2009		2008		2007		2009			2008			2007

United States	$	182,219	$	206,795	$	179,999		71.2	%		82.0	%		83.3	%
Foreign		73,636		45,461		35,970		28.8			18.0			16.7

Total	$	255,855	$	252,256	$	215,969		100.0	%		100.0	%		100.0	%

In the years ended December 31, 2009, 2008 and 2007, 40.0%, 45.2% and 28.1%, respectively, of our revenues attributable to our Product Segments were generated in the United States.

A discussion of the reasons for these changes in the geographical breakdown of our revenues is provided further below in this report.

Seasonality

The prices paid for the electricity generated by our domestic power plants pursuant to our PPAs are subject to seasonal variations. The prices paid for electricity under the PPAs with Southern California Edison, 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 will receive in the future, higher revenues during such months. The prices paid for electricity pursuant to the PPAs of our power plants in Nevada have no significant changes during the year. In the winter, due principally to the lower ambient temperature, our power plants produce more energy and as a result we receive higher energy revenues. However, the higher capacity payments payable by Southern California Edison in California 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 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 include 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, insurance, and for the California power plants, 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 projects 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. For the year ended December 31, 2009, royalties constituted approximately 3.6% of the Electricity Segment revenues, compared to approximately 5.1% in the year ended December 31, 2008.

Product Segment

The principal cost of revenues attributable to our Product Segment include materials, salaries and related employee benefits, expenses related to subcontracting activities, transportation expenses, and sales commissions to sales representatives. Some of the principal expenses attributable to our Product Segment, such as a portion of the costs related to labor, utilities and other support services are fixed, while others, such as materials, construction, transportation and sales commissions, are variable and may fluctuate significantly, depending on market conditions. As a result, the cost of revenues attributable to our Product Segment, expressed as a percentage of total revenues, fluctuates. Another reason for

such fluctuation is that in responding to bids for our products, we price our products and services in relation to existing competition and other prevailing market conditions, which may vary substantially from order to order.

Cash and Cash Equivalents

Our cash and cash equivalents as of December 31, 2009 increased to $46.3 million from $34.4 million as of December 31, 2008. This increase is principally due to the receipt of: (i) proceeds in the amount of $105.0 million from the OrPower 4 financing; (ii) proceeds in the amount of $42.0 million from the Amatitlan Loan; (iii) proceeds in the amount of $40.0 million from long-term loan agreements with two groups of institutional investors; (iv) proceeds in the amount of $50.0 million from a long-term loan agreement with a commercial bank; (v) a net increase of $34.0 million in amounts drawn under revolving credit lines with commercial banks; and (vi) $110.8 million derived from operating activities in the year ended December 31, 2009. The increase in our cash resources was partially offset by our use during the year ended December 31, 2009 of $270.7 million of cash resources to fund capital expenditures and $49.8 million to repay long-term debt to our parent and to third parties. Our corporate borrowing capacity under committed lines of credit with different commercial banks as of December 31, 2009 is $362.5 million, as described below in the section entitled “Liquidity and Capital Resources”, of which we utilized $187.5 million (including $53.5 million of letters of credit).

Critical Accounting Policies

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 the portrayal of our financial position and results of operations. In applying these critical accounting policies, 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 recovered energy-based 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. The PPAs are exempt from derivative treatment due to the normal purchase and sale exception. 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 engineering and operating services and sales of products and parts are recorded once the service is provided or product delivery is made, as applicable.

Revenues generated from the construction of geothermal and recovered energy power plant equipment and other equipment on behalf of third parties (product revenues) are recognized using the percentage of completion method. The percentage of completion method 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 no less than annually for all others, or when circumstances change and warrant a modification to a previous estimate. Changes in job performance, job conditions, and estimated profitability, including those arising from the application of penalty provisions in relevant contracts and final contract settlements, may result in revisions to costs and revenues and are recognized in the period in which the revisions are determined. Provisions for estimated losses relating to contracts are made in the period in which such losses are determined.


	•	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 one to two 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. The up-front non-refundable bonus payments 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.

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 would have to write-off costs associated with the project that were previously capitalized. During the years ended December 31, 2009 and 2008, we determined that the geothermal resource at three of our exploration projects would not support commercial operations and abandoned the sites. As a result of this determination, we expensed $2,367,000 and $9,828,000 of capitalized costs during the years ended December 31, 2009 and 2008, 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 $33,617,000 and $34,958,000 at December 31, 2009 and 2008, 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, construction-in-process, PPAs, and unconsolidated investments for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Factors which could trigger an impairment include, among others, significant underperformance relative to historical or projected future operating results, significant changes in our use of assets or our overall business strategy, negative industry or economic trends, a determination that an exploration project will not support commercial operations, a determination that a suspended project is not likely to be completed, a significant increase in costs necessary to complete a project, legal factors relating to our business or when we conclude that it is more likely than not that an asset will be disposed of or sold.

We test our operating plants that are operated together as a complex for impairment at the complex level because the cash flows of such plants result from significant shared operating activities. For example, the operating power plants in a complex are managed under a combined operation management generally with one central control room that controls 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. We test for impairment 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, 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 our 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. We believe that no impairment exists for long-lived assets; however, estimates as to the recoverability of such assets may change based on revised circumstances. Estimates of the fair value of assets require estimating useful lives and selecting a discount rate that reflects the risk inherent in future cash flows.


	•	Obligations Associated with the Retirement of Long-Lived Assets. We record the fair market value of legal liabilities related to the retirement of our assets in the period in which such liabilities are incurred. Our liabilities related to the retirement of our assets 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 will either settle the obligation for its recorded amount or will report either a gain or a loss with respect thereto. Estimates of the costs associated with asset retirement obligations are based on factors such as prior operations, the location of the assets and specific power plant characteristics. We review and update our cost estimates periodically and adjust our asset retirement obligations in the period in which the revisions are determined. If actual results are not consistent with our assumptions used in estimating our asset retirement obligations, we may incur additional losses that could be material to our financial condition or results of operations.

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

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. Although realization is not assured, management believes it is more likely than not that the deferred tax asset as of December 31, 2009 will be realized. In the event we were to determine that we would not be able to realize all or a portion of our deferred tax assets in the future, we would reduce such amounts through a charge to income in the period in which that determination is made or when tax law changes are enacted.

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 have recorded 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, no tax benefit has been recognized 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

On January 1, 2009, we adopted the guidance for accounting for noncontrolling interests in consolidated financial statements. The adoption of the new accounting standard resulted in retrospective presentation on the condensed consolidated balance sheet as of December 31, 2008 and the condensed consolidated statements of operations and comprehensive income for the years ended December 31, 2008 and 2007.

On April 1, 2009, we adopted the accounting standard for recognition and presentation of other-than-temporary impairments of debt securities. The adoption of this standard resulted in a reclassification of other-than-temporary impairment charges previously recognized in earnings to other comprehensive income (loss) with an offset to retained earnings.

In the year ended December 31, 2009, we adopted the Codification. The Codification became the single source for all authoritative U.S. GAAP recognized by the FASB. The Codification does not change U.S. GAAP and did not have an affect on our financial position, results of operations or liquidity.

See Note 1 to our Consolidated Financial Statements set forth in Item 8 of this annual report for additional information regarding new accounting pronouncements.

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 the following: (i) our recent construction of new power plants and enhancement of acquired power plants; and (ii) fluctuation in revenues from our Product Segment. A number of operational issues in the first quarter of 2007 resulted in both reduced revenues and increased costs for the year ended December 31, 2007.


	Year Ended December 31,
	2009			2008 (As Restated ⁽²⁾ ) ⁽¹⁾			2007 ⁽¹⁾
	(In thousands, except per share data)

Statements of Operations Historical Data:
Revenues:
Electricity	$	255,855		$	252,256		$	215,969
Product		159,389			92,577			79,950

		415,244			344,833			295,919

Cost of revenues:
Electricity		180,156			170,053			148,698
Product		112,450			72,755			68,036

		292,606			242,808			216,734

Gross margin:
Electricity		75,699			82,203			67,271
Product		46,939			19,822			11,914

		122,638			102,025			79,185
Operating expenses:
Research and development expenses		10,502			4,595			3,663
Selling and marketing expenses		14,584			10,885			10,645
General and administrative expenses		26,412			25,938			21,416
Write-off of unsuccessful exploration activities		2,367			9,828			—

Operating income		68,773			50,779			43,461
Other income (expense):
Interest income		639			3,118			6,565
Interest expense, net		(16,241	)		(14,945	)		(29,745	)
Foreign currency translation and transaction gains (losses)		1,107			(7,721	)		(1,339	)
Impairment of auction rate securities		(279	)		(4,195	)		(2,020	)
Income attributable to sale of tax benefits		15,515			18,118			6,488
Gain from extinguishment of liability		13,348			—			—
Other non-operating income, net		479			771			890

Income before income taxes and equity in income of investees		83,341			45,925			24,300
Income tax provision		(16,924	)		(4,358	)		(1,822	)
Equity in income of investees, net		2,136			1,725			4,742

Net income		68,553			43,292			27,220
Net loss attributable to noncontrolling interest		298			316			156

Net income attributable to the Company’s stockholders	$	68,851		$	43,608		$	27,376

Earnings per share — basic and diluted
Basic	$	1.52		$	0.99		$	0.71

Diluted	$	1.51		$	0.98		$	0.70

Weighted average number of shares used in computation of earnings per share:
Basic		45,391			44,182			38,762

Diluted		45,533			44,298			38,880


	Year Ended December 31,
	2009			2008 (As Restated ⁽²⁾ ) ⁽¹⁾			2007 ⁽¹⁾

Statements of Operations Percentage Data:
Revenues:
Electricity		61.6	%		73.2	%		73.0	%
Product		38.4			26.8			27.0

		100.0			100.0			100.0

Cost of revenues:
Electricity		70.4			67.4			68.9
Product		70.6			78.6			85.1

		70.5			70.4			73.2

Gross margin:
Electricity		29.6			32.6			31.1
Product		29.4			21.4			14.9

		29.5			29.6			26.8
Operating expenses:
Research and development expenses		2.5			1.3			1.2
Selling and marketing expenses		3.5			3.2			3.6
General and administrative expenses		6.4			7.5			7.2
Write-off of unsuccessful exploration activities		0.6			2.9			0.0

Operating income		16.6			14.7			14.7
Other income (expense):
Interest income		0.2			0.9			2.2
Interest expense, net		(3.9	)		(4.3	)		(10.1	)
Foreign currency translation and transaction gains (losses)		0.3			(2.2	)		(0.5	)
Impairment of auction rate securities		(0.1	)		(1.2	)		(0.7	)
Income attributable to sale of tax benefits		3.7			4.4			2.2
Gain from extinguishment of liability		3.2			0.0			0.0
Other non-operating income, net		0.1			0.2			0.3

Income before income taxes and equity in income of investees		20.1			12.4			8.2
Income tax provision		(4.1	)		(1.3	)		(0.6	)
Equity in income of investees, net		0.5			0.5			1.6

Net income		16.5			11.7			9.2
Net loss attributable to noncontrolling interest		0.1			0.1			0.1

Net income attributable to the Company’s stockholders		16.6	%		11.8	%		9.3	%


⁽¹⁾		We adopted the new accounting guidance for noncontrolling interests in a subsidiary on January 1, 2009. Under this guidance, noncontrolling interests are to be presented on the balance sheet as a component of equity. The adoption of this standard resulted in retrospective presentation and disclosure changes to the statements of operations data for the years ended December 31, 2008 and 2007. The impact of adopting this standard is more fully described in Note 11 to our consolidated financial statements set forth in Item 8 of this annual report.

⁽²⁾		Restatement

		Through the third quarter of 2009, we accounted for exploration and development costs using an accounting method that is analogous to the full cost method used in the oil and gas industry. Under that method, we capitalized costs incurred in connection with the exploration and development of geothermal resources on an


		“area-of-interest” basis. Each area of interest included a number of potential projects in the state of Nevada that were planned to be operated together with the same operation and maintenance team. Impairment tests were performed on an area-of-interest basis rather than at a single site. Under this methodology, costs associated with projects that we have determined are not economically feasible remained capitalized as long as the area-of-interest was not subject to impairment.


		Following a periodic review performed by the SEC Staff, we concluded that this accounting treatment was inappropriate in certain respects and have restated the 2008 consolidated financial statements to write-off capitalized costs for projects we have determined are not economically feasible in the period such determination was made.

		The effect of the restatement on our results of operations for the year ended December 31, 2008 is as follows:


							As Restated
							Before			Application
							Application of			of New
	As Originally			Restatement			New Accounting			Accounting
	Reported			Adjustment			Standard			Standard			As Restated
							(Dollars in thousands)

Write-off of unsuccessful exploration activities	$	—		$	(9,828	)	$	(9,828	)	$	—		$	(9,828	)

Operating income		60,607			(9,828	)		50,779			—			50,779

Other income (expense):
Interest income		3,118			—			3,118			—			3,118
Interest expense, net		(7,677	)		—			(7,677	)		(7,268	)		(14,945	)
Foreign currency translation and transaction losses		(7,721	)		—			(7,721	)		—			(7,721	)
Income attributable to sale of tax benefits		—			—			—			18,118			18,118
Other non-operating expense, net		(3,424	)		—			(3,424	)		—			(3,424	)

Income before income taxes, minority interest, and equity in income of investees		44,903			(9,828	)		35,075			10,850			45,925
Income tax provision		(7,962	)		3,604			(4,358	)		—			(4,358	)
Minority interest		11,166			—			11,166			(11,166	)		—
Equity in income of investees, net		1,725			—			1,725			—			1,725

Net income		49,832			(6,224	)		43,608			(316	)		43,292
Net loss attributable to noncontrolling interest		—			—			—			316			316

Net income attributable to the Company’s stockholders	$	49,832		$	(6,224	)	$	43,608		$	—		$	43,608

Comparison of the Year Ended December 31, 2009 and the Year Ended December 31, 2008

Total Revenues

Total revenues for the year ended December 31, 2009 were $415.2 million, compared to $344.8 million for the year ended December 31, 2008, which represented a 20.4% increase in total revenues. This increase is primarily attributable to our Product Segment whose revenues increased by 72.2% from the same period in 2008 (for the reasons discussed below). Revenues in our Electricity Segment increased by 1.4% from the same period in 2008.

Electricity Segment

Revenues attributable to our Electricity Segment for the year ended December 31, 2009 were $255.9 million, compared to $252.3 million for the year ended December 31, 2008, which represented a 1.4% increase in such

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revenues. The increase in the Electricity Segment revenues is attributable to an increase of 14.2% in our U.S. and international electricity generation from 2,942,917 MWh in the year ended December 31, 2008 to 3,360,676 MWh in the year ended December 31, 2009. Despite the 14.2% increase in our electricity generation, our electricity revenues increased by a modest 1.4% due to the decline in the average revenue rate of our electricity portfolio from $86 per MWh in the year ended December 31, 2008 to $76 per MWh in the year ended December 31, 2009. The decrease in the average rate is mainly attributable to a decrease in the energy rates in the Puna power plant due to lower oil prices, and the expiration of the Adder paid to us under the Heber 2 PPA at the end of July 2008. The increase in our electricity generation was attributable mainly to the 35 MW Phase II of the Olkaria III complex in Kenya, which started generating electricity in January 2009 and to the 8 MW GDL power plant in New Zealand, which started generating electricity in the fourth quarter of 2008. In the United States, the electricity generation increased due to: (i) the new Galena 3 power plant, which was placed in service in the second half of the first quarter of 2008; and (ii) the restored generating capacity of our Steamboat 2/3 power plant following the replacement of turbines during the second half of 2008. The increase in our generation in the United States in the year ended December 31, 2009 was offset by a temporary decrease in the generating capacity of the Puna power plant due to the enhancement and repair of the geothermal wellfield, which we are undertaking to increase its capacity in advance of an 8 MW expansion

Product Segment

Revenues attributable to our Product Segment for the year ended December 31, 2009 were $159.4 million, compared to $92.6 million for the year ended December 31, 2008, which represented a 72.2% increase in such revenues. Most of this increase in revenues was derived from EPC contracts with third parties for the construction of three large binary geothermal projects, the Blue Mountain project in Nevada, the Centennial Binary Plant in New Zealand, and the Las Pailas project in Costa Rica. While we do not expect revenues and corresponding margins in the Product Segment to continue at this level in 2010, the improving global economy combined with funding and regulatory benefits in the United States should contribute to our future revenues in this segment.

Total Cost of Revenues

Total cost of revenues for the year ended December 31, 2009 was $292.6 million, compared to $242.8 million for the year ended December 31, 2008, which represented a 20.5% increase in total cost of revenues. This increase is primarily attributable to the increase in the cost of revenues in our Product Segments, as discussed below. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2009 was 70.5% compared to 70.4% for the year ended December 31, 2008.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2009 was $180.2 million, compared to $170.1 million for the year ended December 31, 2008, which represented a 5.9% increase in total cost of revenues for such segment. The increase from the same period last year was due to: (i) increased costs (including depreciation) as a result of new and enhanced projects placed into service; (ii) an increase in certain maintenance costs in order to ensure higher availability of geothermal resource during the summer, when electricity rates paid under the relevant PPA are higher; and (iii) increased repair costs of the geothermal wellfield in Puna. This increase was partially offset by decreased royalty costs in the Puna power plant as a result of lower revenues as discussed above. The cost per MWh in the year ended December 31, 2009 decreased compared to the year ended December 31, 2008 due to our higher volume of energy generation. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2009 was 70.4%, compared to 67.4% for the year ended December 31, 2008.

Product Segment

Total cost of revenues attributable to our Product Segment for the year ended December 31, 2009 was $112.5 million, compared to $72.8 million for the year ended December 31, 2008, which represented a 54.6% increase in total cost of revenues related to such segment. This increase is attributable to the increase in our product revenues. Despite the increase in the Product Segment cost of revenues, as a percentage of total Product Segment

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revenues, our total cost of revenues attributable to this segment for the year ended December 31, 2009 decreased from 78.6% for the year ended December 31, 2008 to 70.6%. This decrease is mainly attributable to the higher volume of revenues coupled with a more moderate than estimated increase in our costs as a result of the global decrease in commodities prices.

Research and Development Expenses

Research and development expenses for the year ended December 31, 2009 were $10.5 million, compared to $4.6 million for the year ended December 31, 2008, which represented a 128.6% increase. Our research and development activities during the year ended December 31, 2009 included: (i) an experimental REG plant specifically designed to use the residual energy from the vaporization process at liquefied natural gas regasification terminals; (ii) EGS; and (iii) development of a solar thermal system for the production of electricity. The costs related to an experimental REG plant specifically designed to use the residual energy from the vaporization process at a liquefied natural gas regasification terminal in the amount of $7.5 million relate to a research and development project that includes developing and building a unit at a customer’s premises in Spain. If the development of the unit is not successful we will have to remove the unit from the customer’s site. If the unit operates successfully and passes acceptance test, we will be paid by the customer an amount of approximately $16.0 million which will be recognized as revenue upon acceptance by the customer. The research and development expenses are net of grants from the DOE in the amount of $1.3 million with respect to the EGS project.

Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2009 were $14.6 million, compared to $10.9 million for the year ended December 31, 2008, which represented a 34.0% increase. The increase was due primarily to an increase in expenses related to Product Segment revenues. Selling and marketing expenses for the year ended December 31, 2009 constituted 3.5% of total revenues for such period, compared to 3.2% for the year ended December 31, 2008.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2009 were $26.4 million, compared to $25.9 million for the year ended December 31, 2008, which represented a 1.8% increase. General and administrative expenses for the year ended December 31, 2009 constituted 6.4% of total revenues for such year, compared to 7.5% for the year ended December 31, 2008.

Write-off of Unsuccessful Exploration Activities

Write-off of unsuccessful exploration activities for the year ended December 31, 2009 was $2.4 million, compared to $9.8 million (as restated) for the year ended December 31, 2008. Write-off of unsuccessful exploration activities for the year ended December 31, 2009 relates to the Rock Hills exploration project, which we determined in the third quarter of 2009 would not support commercial operations. Write-off of unsuccessful exploration activities for the year ended December 31, 2008 relates to the Buffalo Valley and Grass Valley exploration projects, which we determined in the fourth quarter of 2008 would not support commercial operations.

Operating Income

Operating income for the year ended December 31, 2009 was $68.8 million, compared to $50.8 million (as restated) for the year ended December 31, 2008. Such increase in operating income was principally attributable to an increase in revenues and gross margin of our Product Segment. Operating income attributable to our Electricity Segment for the year ended December 31, 2009 was $47.3 million, compared to $45.1 million (as restated) for the year ended December 31, 2008. Operating income attributable to our Product Segment for the year ended December 31, 2009 was $21.5 million, compared to $5.7 million for the year ended December 31, 2008.

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Interest Income

Interest income for the year ended December 31, 2009 was $0.6 million, compared to $3.1 million for the year ended December 31, 2008, which represented a 79.5% decrease. The decrease is primarily due to a decrease in cash and cash equivalents, marketable securities and restricted cash during the year ended December 31, 2009, as well as a decrease in interest rates payable on investments.

Interest Expense, Net

Interest expense, net, for the year ended December 31, 2009 was $16.2 million, compared to $14.9 million for the year ended December 31, 2008, which represented an 8.7% increase. The $1.3 million increase is primarily due to: (i) an increase in interest expenses related to our long-term project finance loans of the Olkaria III and Amatitlan power plants; (ii) borrowings under our revolving credit lines with banks; and (iii) loan agreements with two groups of institutional investors and a commercial bank. The increase was partially offset by an increase of $6.1 million in interest capitalized to projects primarily as a result of increased costs for projects under construction, as well as principal repayments.

During the year ended December 31, 2009, we capitalized $27.4 million in interest related to projects under construction. We expect this amount to decrease significantly beginning in 2010 due to a lower volume of projects under construction and the commencement of commercial operations of our North Brawley power plant in January 2010.

Foreign Currency Translation and Transaction Gains (Losses)

Foreign currency translation and transaction gains for the year ended December 31, 2009 were $1.1 million, compared to foreign currency translation and transaction losses of $7.7 million for the year ended December 31, 2008. The $8.8 million increase is primarily due to: (i) foreign currency translation gains in the amount of $2.7 million for the year ended December 31, 2009 compared to foreign currency translation losses in the amount of $3.3 million for the year ended December 31, 2008 with respect to a loan denominated in New Zealand dollars, which was granted to our New Zealand subsidiary, GDL, whose functional currency is the New Zealand dollar; and (ii) a decrease in losses on forward foreign exchange transactions which do not qualify as hedge transactions for accounting purposes.

Impaiment of Auction Rate Securities

In the year ended December 31, 2009, we recorded $0.3 million of impairment charges as a result of other-than-temporary declines in the value of certain auction rate securities, compared to $4.2 million in the year ended December 31, 2008. The carrying value of auction rate securities as of December 31, 2009 was $3.2 million.

Income Attributable to Sale of Tax Benefits

Income from the sale of tax benefits to institutional equity investors (as described in “OPC Transaction”) for the year ended December 31, 2009 was $15.5 million, compared to $18.1 million for the year ended December 31, 2008. This income represents the value of PTCs and taxable income or loss generated by OPC and allocated to the investors. The decrease is due to lower depreciation for tax purposes as a result of declining depreciation rates utilizing MACRS and to the purchase of Class B membership units of OPC from Lehman-OPC as described under “Gain from Extinguishment of Liability” below.

Gain from Extinguishment of Liability

Gain from extinguishment of liability for the year ended December 31, 2009 was $13.3 million. On October 30, 2009, Ormat Nevada acquired Lehman-OPC’s thirty percent interest in the Class B membership units of OPC. The membership units were acquired from 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. As a result, the repurchase of these interests at a discount resulted in a pre-tax gain of $13.3 million. In addition, an amount of approximately $1.1 million has been classified from noncontrolling interest to additional paid-in capital representing the 1.5% residual interest of Lehman-OPC’s Class B membership units.

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Income Taxes

Income tax provision for the year ended December 31, 2009 was $16.9 million, compared to $4.4 million (as restated) for the year ended December 31, 2008. The effective tax rate for the year ended December 31, 2009 and 2008 was 20.3% and 9.5%, respectively. The increase in the effective tax rate primarily resulted from a lower impact of PTCs on the effective tax rate for the year ended December 31, 2009 due to the increase in our income before income taxes.

Equity in Income of Investees

Our participation in the income generated from our investees for the year ended December 31, 2009 was $2.1 million, compared to $1.7 million for the year ended December 31, 2008. The amount is derived mainly from our 50% ownership of the Mammoth complex.

Net Income

Net income for the year ended December 31, 2009 was $68.6 million, compared to $43.3 million (as restated) for the year ended December 31, 2008, which represents an increase of 58.4%. Such increase in net income was principally attributable to: (i) an increase of $18.0 million in our operating income; (ii) an increase of $8.8 million in foreign currency transaction and translation gains; (iii) a decrease of $3.9 million in impairment of auction rate securities; (iv) a $7.2 million decrease in the write off of unsuccessful exploration activities; and (v) a $13.3 million gain from extinguishment of liability. This increase was partially offset by: (i) a $12.6 million increase in income tax provision; (ii) a $2.5 million decrease in interest income; (iii) a $1.3 million increase in interest expense, net; and (iv) a $2.6 million decrease in income attributable to sale of tax benefits.

Comparison of the Year Ended December 31, 2008 and the Year Ended December 31, 2007

Total Revenues

Total revenues for the year ended December 31, 2008 were $344.8 million, compared to $296.0 million for the year ended December 31, 2007, which represented a 16.5% increase in total revenues. This increase is attributable to both our Electricity and Product Segments whose revenues increased by 16.8% and 15.8%, respectively, over the same period in 2007.

Electricity Segment

Revenues attributable to our Electricity Segment for the year ended December 31, 2008 were $252.3 million, compared to $216.0 million for the year ended December 31, 2007, which represented a 16.8% increase in such revenues. This increase is primarily attributable to additional revenues of $36.3 million resulting from an increase in our electricity generation, as a result of new power plants placed in service and enhanced performance of existing power plants (as described below), from 2,513,348 MWh in the year ended December 31, 2007 to 2,942,917 MWh in the year ended December 31, 2008. The average revenue rate of our electricity portfolio in both years was approximately $86 per MWh. Revenues from our international plants increased by $9.5 million as a result of revenues generated from our Amatitlan power plant in Guatemala, which started generating electricity in March 2007 and from our Momotombo power plant in Nicaragua, which suffered in the year ended December 31, 2007 from a failure of turbines that we did not manufacture. The increase of $26.8 million in our United States electricity revenues was offset by: (i) a decrease in the generation of the Steamboat 2/3 power plant as a result of the temporary shut down required to replace the power plant turbines (the power plant returned to full operation in the beginning of October 2008); (ii) expiration of the Adder paid to us under the Heber 2 PPA; (iii) a decrease in the generating output of the Brady complex as a result of a decline in the geothermal reservoir; and (iv) a decrease in the generating output of the OREG 1 power plant as a result of lower than expected heat availability due to operation of the compressor stations at a lower than expected load.

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Product Segment

Revenues attributable to our Product Segment for the year ended December 31, 2008 were $92.6 million, compared to $80.0 million for the year ended December 31, 2007, which represented a 15.8% increase in such revenues. Most of the increase in revenues was derived from two large binary geothermal projects, the Blue Mountain project in Nevada and the Centennial Binary Plant in New Zealand.

Total Cost of Revenues

Total cost of revenues for the year ended December 31, 2008 was $242.8 million, compared to $216.7 million for the year ended December 31, 2007, which represented a 12.0% increase in total cost of revenues. The increase is attributable to an increase in both our Electricity and Product Segments, as discussed below. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2008 was 70.4% compared to 73.2% for the year ended December 31, 2007.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2008 was $170.1 million, compared to $148.6 million for the year ended December 31, 2007, which represented a 14.4% increase in total cost of revenues for such segment. The increase in our costs in this segment during the year ended December 31, 2008 over the same period in 2007 reflects: (i) increased costs relating to new and enhanced power plants placed in service (including depreciation); (ii) an increase in labor and materials costs in existing plants; and (iii) liquidated damages to our customers as a result of not meeting the capacity targets under certain PPAs. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2008 was 67.4% compared with 68.9% for the year ended December 31, 2007.

Product Segment

Total cost of revenues attributable to our Product Segment for the year ended December 31, 2008 was $72.8 million compared to $68.0 million for the year ended December 31, 2007, which represented a 6.9% increase in total cost of revenues related to such segment. This increase is attributable to the increase in our product revenues, as described above, as well as a different product mix. As a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment for the year ended December 31, 2008 was 78.6% compared to 85.1% for the year ended December 31, 2007.

Research and Development Expenses

Research and development expenses for the year ended December 31, 2008 were $4.6 million, compared to $3.7 million for the year ended December 31, 2007, which represented a 25.4% increase. Such increase is primarily due to expenses incurred in connection with our research and development activities relating to: (i) EGS; (ii) an experimental REG plant specifically designed to use the residual energy from the vaporization process at a liquefied natural gas regasification terminal (as a result of receiving a notice to proceed with the construction of such unit from ENAGAS, S.A. of Madrid, Spain); (iii) development of a solar thermal system for the production of electricity; and (iv) the supply of a geothermal power unit for testing at a producing oil well located at the Oil Test Center near Caspar, Wyoming. The research and development expenses are net of grants from the DOE in the amount of $0.6 million with respect to the EGS project.

Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2008 were $10.9 million, compared to $10.6 million for the year ended December 31, 2007, which represented a 2.3% increase. Selling and marketing expenses for the year ended December 31, 2008 constituted 3.2% of total revenues for such period, compared to 3.6% for the year ended December 31, 2007.

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General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2008 were $25.9 million, compared to $21.4 million for the year ended December 31, 2007, which represented a 21.1% increase. Such increase is primarily attributable to: (i) costs related to a potential acquisition of geothermal assets that we ultimately decided not to pursue; and (ii) an increase in personnel expenses due in part to the devaluation of the U.S. dollar during the year ended December 31, 2008. General and administrative expenses for the year ended December 31, 2008 increased to 7.5% of total revenues for such period, from 7.2% for the year ended December 31, 2007.

Write-off of Unsuccessful Exploration Activities

Write-off of unsuccessful exploration activities for the year ended December 31, 2008 was $9.8 million, which represents the write-off of capitalized costs related to the Buffalo Valley and Grass Valley exploration projects, which we determined in the fourth quarter of 2008 would not support commercial operation.

Operating Income

Operating income for the year ended December 31, 2008 was $50.8 million (as restated), compared to $43.5 million for the year ended December 31, 2007. Such increase in operating income was principally attributable to an increase in the gross margin in both our Electricity and Product Segments due to the significant increase in revenues during the year ended December 31, 2008, as described above. The increase in operating income was partially offset by to the write-off of unsuccessful exploration activities. Operating income attributable to our Electricity Segment for the year ended December 31, 2008 was $45.1 million (as restated), compared to $43.7 million for the year ended December 31, 2007. Operating income attributable to our Product Segment for the year ended December 31, 2008 was $5.7 million, compared to an operating loss of $0.2 million for the year ended December 31, 2007.

Interest Income

Interest income for the year ended December 31, 2008 was $3.1 million, compared to $6.6 million for the year ended December 31, 2007, which represented a 52.5% decrease. The decrease is primarily due to a decrease in cash and cash equivalents, marketable securities and restricted cash as well as a decrease in interest rates payable on liquid investments.

Interest Expense, Net

Interest expense, net, for the year ended December 31, 2008 was $14.9 million, compared to $29.7 million for the year ended December 31, 2007, which represented a 49.8% decrease. The $14.8 million decrease is primarily due to principal repayments and to an increase of $14.5 million in interest capitalized to projects as a result of increased projects under construction. The decrease was partially offset by a $4.5 million in interest expenses related to the sale tax benefits in OPC.

Foreign Currency Translation and Transaction Losses

Foreign currency translation and transaction losses for the year ended December 31, 2008 were $7.7 million, compared to $1.3 million for the year ended December 31, 2007. The $6.4 million increase is primarily due to: (i) foreign currency translation losses in the amount of $3.3 million with respect to a loan denominated in New Zealand dollars which was granted to our New Zealand subsidiary GDL, whose functional currency is the New Zealand dollar; and (ii) losses on forward foreign exchange transactions which do not qualify as hedge transactions for accounting purposes. The foreign currency translation losses in respect of the loan granted to our New Zealand subsidiary will decrease the cost of the equipment which was financed by such loan.

Impairment of Auction Rate Securities

In the year ended December 31, 2008, we recorded $4.2 million of impairment charges as a result of other-than-temporary decline in the value of certain auction rate securities compared to $2.0 million in the year

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ended December 31, 2007. This amount includes $0.8 million, which was deemed temporary as of December 31, 2007. See also Note 5 to our consolidated financial statements set forth in Item 8 of this annual report. The carrying value of auction rate securities as of December 31, 2008 was $4.9 million.

Income Attributable to Sale of Tax Benefits

Income from the sale of tax benefits in OPC to institutional equity investors (as described in “OPC Transaction”) for the year ended December 31, 2008 was $18.1 million, compared to $6.5 million for the year ended December 31, 2007. This income represents the value of PTCs and taxable income or loss generated by OPC and allocated to the investors. The increase is a result of additional tax benefits as a result of higher tax benefits in existing power plants which operated a full year in the year ended December 31, 2008 as well as the transfer of the Galena 3 power plant to OPC in April 2008, which power plant benefits from higher depreciation for tax purposes as a result of utilizing MACRS.

Income Taxes

Income tax provision for the year ended December 31, 2008 was $4.4 million (as restated), compared to $1.8 million for the year ended December 31, 2007. The effective tax rates for the years ended December 31, 2008 and 2007 were 9.5% and 7.5%, respectively. The increase in the effective tax rate resulted from the sale of tax benefits in OPC to institutional equity investors as discussed above and a lower impact on the effective tax rate from PTCs in the year ended December 31, 2008 due to an increase in our income before income taxes.

Equity in Income of Investees

Our participation in the income generated from our investees for the year ended December 31, 2008 was $1.7 million, compared to $4.7 million for the year ended December 31, 2007. In the year ended December 31, 2008 the amount was derived from our 50% ownership of the Mammoth complex, while in the year ended December 31, 2007 it was derived from our 50% ownership in the Mammoth complex and from our 80% ownership in our equity investee, OLCL. On September 25, 2007, OLCL transferred its power plants to PNOC-Energy Development Corporation pursuant to a Build, Operate, and Transfer agreement. We did not incur any material financial loss as a result of such transfer, although this transfer reduced our owned foreign generation capacity by 39 MW, with a commensurate impact on equity in income of investees and net income. Our equity in income of investees for the year ended December 31, 2008 included an immaterial loss from OLCL, while in the year ended December 31, 2007 we had $3.1 million of income from OLCL.

Net Income

Net income for the year ended December 31, 2008 was $43.3 million (as restated), compared to $27.2 million for the year ended December 31, 2007, which represents an increase of 59.0%. Such increase in net income was principally attributable to: (i) a $7.3 million increase in our operating income; (ii) a $14.8 million decrease in interest expense; and (iii) an $11.6 million increase in income attributable to sale of tax benefits as described above. This was partially offset by: (i) a $2.5 million increase in income tax provision; (ii) a $3.0 million decrease in equity in income of investees; (iii) a $2.2 million increase in impairment of auction rate securities; (iv) a $3.4 million decrease in interest income; (v) a $6.4 million increase in foreign currency translation and transaction losses; and (vi) a $9.8 million write off of unsuccessful exploration activities.

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, issuance by OFC and OrCal of their respective Senior Secured Notes and project financing (including the Puna lease and the OPC Transaction described below) and we have utilized this cash to fund our acquisitions, develop and construct power generation plants and meet our other cash and liquidity needs.

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As of December 31, 2009, we have access to the following sources of funds: (i) $46.3 million in cash and cash equivalents; and (ii) $175.0 million of unused corporate borrowing capacity under existing lines of credit with different commercial banks.

Our estimated capital needs for 2010 include approximately $364.0 million for capital expenditures on new projects under development or construction, exploration activity, operating projects and machinery and equipment, as well as $61.8 million for debt repayment (including to our parent).

We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) cash flows from our operations; (iii) additional borrowing capacity under future lines of credit with commercial banks that are under negotiations; (iv) future project financing and refinancing; and (v) a cash grant available to us under the ARRA in respect of the North Brawley power plant. Our management believes that these sources will address our anticipated liquidity, capital expenditures, and other investment requirements. Our shelf registration statement on Form S-3, which was declared effective on October 2, 2008, provides us with the ability to raise additional capital of up to $1.5 billion through the issuance of securities, subject to market conditions.

Loan Agreements with our Parent

Under a loan agreement with Ormat Industries Ltd. (our parent company), Ormat Industries agreed to make a loan to us in one or more advances not exceeding a total aggregate amount of $150.0 million. The proceeds of the loan were used to fund our general corporate activities and investments. We are required to repay the loan and accrued interest in full and in accordance with an agreed-upon repayment schedule and in any event on or prior to June 5, 2010. Interest on the loan is calculated on the balance from the date of the receipt of each advance until the date of payment thereof at a fixed rate of 7.5% per annum. Interest is calculated by Ormat Industries on the basis of a year consisting of 360 days. As of December 31, 2009, the outstanding balance of the loan was approximately $9.6 million compared to $26.2 million as of December 31, 2008.

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 under the heading “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 under the heading “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 in an offering subject to Rule 144A and Regulation S of the Securities Act, for the purpose of refinancing the acquisition cost of the Brady, Ormesa and Steamboat 1/1A projects, and the financing of the acquisition cost of the Steamboat 2/3 project. 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 which commenced on June 30, 2004. 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 and payment of dividends. As of December 31, 2009, OFC was in compliance with the covenants under the OFC Senior Secured Notes. As of December 31, 2009, there were $146.3 million of OFC Senior Secured Notes outstanding.

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 in an offering subject to Rule 144A and Regulation S of the Securities Act, for the purpose of refinancing the acquisition cost of the Heber projects. The OrCal Senior Secured Notes have been rated BBB- by Fitch. The OrCal

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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 that commenced on June 30, 2006. 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 and payment of dividends. As of December 31, 2009, OrCal was in compliance with the covenants under the OrCal Senior Secured Notes. As of December 31, 2009, there were $105.8 million of OrCal Senior Secured Notes outstanding.

Olkaria III Loan — Non-Recourse

In March 2009, OrPower 4 closed a project financing loan of $105.0 million to refinance its investment in the 48 MW Olkaria III complex located in Kenya. We initially financed construction of Phase I and Phase II of the project, as well as the drilling of wells, with our own funds. The loan is provided by a group of European DFIs arranged by DEG. The first disbursement of $90.0 million was made on March 23, 2009 and the second disbursement of $15.0 million was made on July 10, 2009. The 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%, but we had the option to fix the interest rate upon each disbursement. We fixed the interest rate on $77.0 million of the loan at 6.90% per annum. There are various restrictive covenants under the loan, which include limitations on OrPower 4’s ability to make distributions to its shareholders. Management believes that as of December 31, 2009, OrPower 4 was in compliance with the covenants under the loan. As of December 31, 2009, $99.5 million of the above loan was outstanding.

Amatitlan Loan — Non-Recourse

In May 2009, Ortitlan entered into a note purchase agreement in an aggregate principal amount of $42.0 million to refinance its investment in the 20 MW Amatitlan geothermal power plant located in Amatitlan, Guatemala. We initially financed the construction of the project, as well as the drilling of wells with corporate funds. The loan was provided by TCW Global Project Fund II, Ltd. The loan will mature on June 15, 2016, and is payable in 28 quarterly installments. The annual interest rate on the loan is 9.83%, but the effective cost for us is approximately 8%, due to the elimination, following the refinancing, of the political risk insurance premiums that we had been paying on our equity investment in the project. There are various restrictive covenants under the loan, which include limitations on Ortitlan’s ability to make distributions to its shareholders. Management believes that as of December 31, 2009, Ortitlan was in compliance with the covenants under the loan. As of December 31, 2009, $41.0 million of the above loan was outstanding.

Senior Loans from IFC and CDC — Non-Recourse

Orzunil has senior loan agreements with IFC and CDC. The loan from IFC, of which $3.3 million was outstanding as of December 31, 2009, has a fixed annual interest rate of 11.775%, and matures on November 15, 2011. The loan from CDC, of which $2.0 million was outstanding as of December 31, 2009, has a fixed annual interest rate of 10.300%, and matures on August 15, 2010. There are various restrictive covenants under these senior loans, which include limitations on Orzunil’s ability to make distributions to its shareholders. As of December 31, 2009, Orzunil was in compliance with the covenants under these senior loans.

Credit Facility Agreement (The Momotombo project) — Limited-Recourse

OMPC has a loan agreement with Bank Hapoalim, of which $2.6 million was outstanding as of December 31, 2009, bearing an interest rate of 3-month LIBOR plus 2.375% per annum on tranche one of the loan and 3-month LIBOR plus 3.0% per annum on tranche two of the loan. Tranche one of the loan matures on September 5, 2010, and is payable in 32 quarterly installments of $298,000 each, and tranche two of the loan matures on December 5, 2010, and is payable in 28 quarterly installments of $424,000 each. There are various restrictive covenants under this loan, which include limitations on OMPC’s ability to make distributions to its shareholders. As of December 31, 2009, OMPC was in compliance with the covenants under the above loan.

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New Financing of our Projects

Financing of the North Brawley Power Plant

As a result of the recent ARRA, we intend to refinance the equity invested in the North Brawley power plant partially with a cash grant available to us under the ARRA and with long-term debt of approximately $100 million that we are currently negotiating with a financial institution.

Full-Recourse Third-Party Debt

In December 2008, our subsidiary, Ormat Nevada, entered into an amendment of its credit agreement with Union Bank, extending the final maturity of the facility and increasing its total amount to $37.5 million. Under the credit agreement, Ormat Nevada can request extensions of credit in the form of loans and/or the issuance of one or more 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 have 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 by any of its (or any of its subsidiaries’) assets.

Loans and draws under the letters of credit (if any) under the credit agreement will bear interest at a floating rate based on the Eurodollar plus a margin. There are various restrictive covenants under the credit agreement, which include maintaining certain levels of tangible net worth, leverage ratio, minimum coverage ratio, and a distribution coverage ratio. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios.

As of December 31, 2009, letters of credit in the total amount of $35.4 million remain issued and outstanding under this credit agreement with Union Bank.

We also have credit agreements with five commercial banks for an aggregate amount of $310.0 million. Under these credit agreements, we or our Israeli subsidiary, Ormat Systems, can request extensions of credit in the form of loans and/or the issuance of one or more letters of credit. Each of the credit agreements has a term of three years.

In October 2009, we entered into an additional credit agreement with another commercial bank in the amount of $15.0 million. Under this credit agreement, we or our Israeli subsidiary, Ormat Systems, can request extensions of credit in the form of loans and/or the issuance of one or more letters of credit. This credit agreement has a term of two years.

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, 2009, loans in the amount of $134.0 million were outstanding, and letters of credit in the total amount of $18.1 million remain issued and outstanding under such credit agreements.

In July 2009, we entered into a 6-year loan agreement of $20.0 million with a group of institutional investors. The loan matures on July 16, 2015, is payable in 12 semi-annual installments commencing January 16, 2010, and bears annual interest of 6.5%. As of December 31, 2009, $20.0 million of the above loan was outstanding.

In July 2009, we entered into an 8-year loan agreement of $20.0 million with a group of institutional investors. The loan 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, 2009, $20.0 million of the above loan was outstanding.

In November 2009, we 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 commencing May 10, 2010. The loan bears interest at 6-month LIBOR plus 3.25%, and we have the option to fix the interest rate upon the drawing of the loan. As of December 31, 2009, $50.0 million of the above loan was outstanding.

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Our obligations under the credit and loan agreements are unsecured, but we are subject to a negative pledge in favor of the banks 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. In some cases, we have agreed to maintain certain financial ratios such as a debt service coverage ratio and a debt to equity ratio. 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.

Some of the credit and loan agreements contain cross-default provisions with respect to other material indebtedness owed by us to any third party.

We are currently in compliance with our covenants with respect to these credit and loan agreements, 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 plan of 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.

Two commercial banks have issued such performance letters of credit in favor of our customers from time to time. As of December 31, 2009, such banks have agreed to make available to us letters of credit totaling $54.6 million. As of such date, such banks have issued letters of credit in the amount of $42.2 million. These letters of credit were not issued under the credit agreements discussed under “Full-Recourse Third-Party Debt” above.

In addition, we and certain of our subsidiaries may request letters of credit under the credit agreements with Union Bank and six other commercial banks as described above under “Full-Recourse Third-Party Debt”. As of December 31, 2009, letters of credit in the total amount of $53.4 million remained issued and outstanding under the abovementioned credit agreements.

Puna Project Lease Transactions

On May 19, 2005, our subsidiary in Hawaii, PGV, entered into a transaction involving the Puna geothermal power plant located on the Big Island of Hawaii. 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 a deferred lease income in the amount of $83.0 million.

OPC Transaction

In June 2007, our wholly owned subsidiary, Ormat Nevada, entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. (Morgan Stanley Geothermal LLC and Lehman-OPC), 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.

The first closing under the agreements occurred in 2007 and covered the Company’s Desert Peak 2, Steamboat Hills and Galena 2 power plants. The investors paid $71.8 million at the first closing. The second closing under the agreements occurred in 2008 and covered the Galena 3 power plant. The investors paid $63.0 million at the second closing.

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Ormat Nevada continues to operate and maintain the power plants and will receive initially all of the distributable cash flow generated by the power plants until it recovers the capital that it has invested in the power plants, while the investors will receive substantially all of the PTCs and the taxable income or loss, and the distributable cash flow after Ormat Nevada has recovered its capital. 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 Flip Date), Ormat Nevada will receive 95% of both distributable cash and taxable income, on a going forward basis. Following the 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.

Our voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. We own, through our subsidiary, Ormat Nevada, all of the Class A membership units, which represent 75% of the voting rights in OPC and 30% of the Class B membership units, which represent 7.5% of the voting rights of OPC, and in total we have 82.5% of the voting rights in OPC. The investors own 70% of the Class B membership units, which represent 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 Flip Date, Ormat Nevada’s voting rights will increase to 96.5% and the investor’s voting rights will decrease to 3.5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the Flip Date and therefore has continued to consolidate OPC.

The bankruptcy of Lehman Brothers Inc. did not adversely affect the OPC Transaction or any other transaction that we entered into with Lehman Brothers Inc. 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.

Liquidity Impact of Uncertain Tax Positions

As discussed in Note 16 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 $4.9 million as of December 31, 2009. 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, but do not believe that the ultimate settlement of our obligations will materially affect our liquidity.

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Dividend

The following are the dividends we declared during the past two years:


	Dividend
	Amount
Date Declared	per Share		Record Date	Payment Date

February 26, 2008	$	0.05	March 14, 2008	March 27, 2008
May 6, 2008	$	0.05	May 20, 2008	May 27, 2008
August 5, 2008	$	0.05	August 19, 2008	August 29, 2008
November 5, 2008	$	0.05	November 19, 2008	December 1, 2008
February 24, 2009	$	0.07	March 16, 2009	March 26, 2009
May 8, 2009	$	0.06	May 20, 2009	May 27, 2009
August 5, 2009	$	0.06	August 18, 2009	August 27, 2009
November 4, 2009	$	0.06	November 18, 2009	December 1, 2009
February 23, 2010	$	0.12	March 16, 2010	March 25, 2010

Historical Cash Flows

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


	Year Ended December 31,
	2009			2008			2007
	(In thousands)

Net cash provided by operating activities	$	110,772		$	116,949		$	58,725
Net cash used in investing activities		(286,036	)		(398,991	)		(116,311	)
Net cash provided by financing activities		187,036			269,286			84,559
Translation adjustments on cash and cash equivalents		142			(78	)		—
Net change in cash and cash equivalents		11,914			(12,834	)		26,973

For the Year Ended December 31, 2009

Net cash provided by operating activities for the year ended December 31, 2009 was $110.8 million, compared to $116.9 million for the year ended December 31, 2008. The net decrease of $6.1 million resulted primarily from: (i) the net increase in costs and estimated earnings in excess of billings on uncompleted contracts of $20.0 million in the year ended December 31, 2009 compared to net decrease of $7.5 million in the year ended December 31, 2008; and (ii) a decrease in accounts payable and accrued expenses of $2.0 million in the year ended December 31, 2008, compared to an increase of $13.5 million in the year ended December 31, 2009. Such decrease was partially offset by: (i) the increase in net income to $68.6 million in the year ended December 31, 2009 from $43.3 million (as restated) in the year ended December 31, 2008, as described above; and (ii) a decrease in receivables and prepaid expenses of $8.1 million in the year ended December 31, 2009, compared to an increase of $15.5 million in the year ended December 31, 2008.

Net cash used in investing activities for the year ended December 31, 2009 was $286.0 million, compared to $399.0 million for the year ended December 31, 2008. The principal factors that affected our net cash used in investing activities during the year ended December 31, 2009 were capital expenditures of $270.6 million, primarily for our facilities under construction, and a $15.9 million increase in restricted cash, cash equivalents and marketable securities.

Net cash provided by financing activities for the year ended December 31, 2009 was $187.0 million, compared to $269.3 million for the year ended December 31, 2008. The principal factors that affected the cash flows provided by financing activities during the year ended December 31, 2009 were: (i) the proceeds of $105.0 million from the Olkaria III Loan; (ii) proceeds of $42.0 million from the Amatitlan Loan; (iii) $34.0 million increase in amounts drawn under revolving lines of credit from banks; (iv) proceeds of $40.0 million from long-term loan agreements with two groups of institutional investors; and (v) proceeds of $50.0 million from long-term loan agreement with a

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commercial bank, offset by: (i) the repayment of long-term debt to our parent in the amount of $16.6 million; (ii) the repayment of debt to third parties in the amount of $33.2 million; and (iii) the payment of a dividend to our shareholders in the amount of $11.3 million.

For the Year Ended December 31, 2008

Net cash provided by operating activities for the year ended December 31, 2008 was $116.9 million, compared to $58.7 million for the year ended December 31, 2007. Such net increase of $58.2 million resulted primarily from: (i) the increase in net income to $43.3 million (as restated) in the year ended December 31, 2008, compared to $27.2 million in the year ended December 31, 2007, mainly as a result of the increase in operating income, as described above; and (ii) an increase of $13.5 million in accounts payable and accrued expenses, in the year ended December 31, 2008, compared to a decrease of $12.2 million in the year ended December 31, 2007.

Net cash used in investing activities for the year ended December 31, 2008 was $399.0 million, compared to $116.3 million for the year ended December 31, 2007. The principal factors that affected our net cash used in investing activities during the year ended December 31, 2008 were capital expenditures of $416.6 million, primarily for our facilities under construction, offset by a $5.6 million decrease in restricted cash, cash equivalents and marketable securities, and by a $12.6 million decrease in marketable securities.

Net cash provided by financing activities for the year ended December 31, 2008 was $269.3 million, compared to $84.6 million for the year ended December 31, 2007. The principal factors that affected the cash flows provided by financing activities during the year ended December 31, 2008 were: (i) the net proceeds of $149.7 million from the sale of 3,100,000 shares in a block trade; (ii) the $33.3 million net proceeds from our sale of 693,750 shares to our parent; (iii) the $63.0 million in net proceeds received from the institutional equity investors in OPC for the transfer of the Galena 3 geothermal project to OPC, relating to the second closing of the OPC Transaction; and (iv) the proceeds of $100.0 million from revolving lines of credit from banks, offset by: (i) the repayment of debt to our parent in the amount of $31.6 million; (ii) the repayment of debt to third parties in the amount of $34.1 million; and (iii) the payment of a dividend to our shareholders in the amount of $8.9 million.

Adjusted EBITDA

Adjusted EBITDA for the year ended December 31, 2009 increased to $167.0 million compared to $121.9 million (as restated) for the year ended December 31, 2008. Adjusted EBITDA for the year ended December 31, 2008 increased to $121.9 million (as restated) compared to $111.4 million for the year ended December 31, 2007. Adjusted EBITDA includes consolidated EBITDA and the Company’s share in the interest, taxes, depreciation and amortization related to the Company’s unconsolidated 50% interest in the Mammoth complex.

We calculate EBITDA as net income before interest, taxes, depreciation and amortization. We calculate adjusted EBITDA to include 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 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. The following table reconciles net cash provided

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by operating activities to EBITDA and adjusted EBITDA, for the years ended December 31 2009, and 2008 (after giving effect to the restatement):


	Year Ended December 31,
	2009			2008 (As Restated)			2007
	(In thousands)

Net cash provided by operating activities	$	110,772		$	116,949		$	58,725
Adjusted for:
Interest expense, net (excluding amortization of deferred financing costs)		13,623			13,590			28,375
Interest income		(639	)		(3,118	)		(6,565	)
Income tax provision (benefit)		16,924			4,358			1,822
Adjustments to reconcile net income to net cash provided by operating activities (excluding depreciation and amortization)		22,392			(13,529	)		19,132

EBITDA		163,072			118,250			101,489
Interest, taxes, depreciation and amortization attributable to the Company’s equity in Mammoth-Pacific L.P.		3,891			3,636			9,881

Adjusted EBITDA	$	166,963		$	121,886		$	111,370

This comparative non-GAAP information is provided to assist investors in evaluating the impact of the change in the way we calculate these amounts in performing their financial analysis of our operations for the periods presented. 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.

Capital Expenditures

Our capital expenditures primarily relate to the following components: (i) the development and construction of new power plants (ii) the enhancement of our existing power plants; (iii) the exploration of leases for geothermal resources; and (iv) the capital expenditure requirements for our operating power plants. We expect that these capital expenditures requirements will be funded initially from internally generated cash or other available corporate resources. We expect to refinance our investments in new projects with limited or non-recourse debt at the project level.

We have estimated approximately $644.0 million for construction of new projects that are still under construction and have invested approximately $156.6 million of such estimate as of December 31, 2009. We expect to invest approximately $275.8 million for these power plants in 2010 (including North Brawley project). In addition, we expect to invest $54.2 million in 2010 in new projects under development

In addition, our operating power plants have capital expenditure requirements for 2010 of approximately $14.8 million. We have various leases for geothermal resources, in which we have started exploration activity, for a total investment amount of approximately $15.4 million for 2010 and we also plan to invest $3.6 million in our production facilities.

Exposure to Market Risks

The recent worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets have led to a worldwide economic recession which may last for an extended period. Based on current conditions, we believe that we have sufficient financial resources to fund our activities and execute our business plan during the next twelve months. However, if worldwide economic conditions worsen, the cost of obtaining financing for our project needs may increase significantly or such financing may not be available at all. In addition, a prolonged economic slowdown could reduce worldwide demand for energy, including our geothermal energy, REG and other products. If these conditions continue or

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worsen, they may result in reduced worldwide demand for energy, which may adversely affect both our Electricity and Product Segments. Among other things, we might face: (i) potential declines in revenues in our Product Segment due to reduced orders or other factors caused by economic challenges faced by our customers and prospective customers; (ii) potential declines in revenues from some of our existing geothermal power projects as a result of curtailed electricity demand and low oil and gas prices; and (iii) potential adverse impacts on our customers’ ability to pay, when due, amounts payable to us. In addition, we may experience related increases in our cost of capital associated with any increased working capital or borrowing needs we may have if our customers do not pay, or if we are unable 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.

One market risk to which power plants are typically exposed is the volatility of electricity prices. However, our exposure to such market risk is currently limited because our long-term PPAs (except for Puna) 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 will be determined by reference to the relevant power purchaser’s short run avoided costs. The Puna power plant is currently benefiting from energy prices which are higher than the floor under the Puna PPA as a result of the high fuel costs that impact HELCO’s avoided costs.

As of December 31, 2009, 63.3% of our consolidated long-term debt (including amounts owed to our parent) was in the form of fixed rate securities and therefore not subject to interest rate volatility risk. As of such date, 36.7% of our debt was in the form of a floating rate instrument, exposing us to changes in interest rates in connection therewith. As of December 31, 2009, $233.0 million of our debt remained subject to some floating rate risk.

We currently maintain our surplus cash in short-term, interest-bearing bank deposits, money market securities, commercial paper and auction rate securities (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. Auction rate securities are securities that are structured with short-term interest rate reset dates of generally less than ninety days but with contractual maturities that can be well in excess of ten years. At the end of each reset period, which depending on the security can occur on a daily, weekly, or monthly basis, investors can sell or continue to hold the securities at par. These securities are subject to fluctuations in fair value depending on the supply and demand at each auction.

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 any of our foreign subsidiaries borrows funds or incurs operating or other expenses in one type of currency but receives 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. In the past, we have not used any material foreign currency exchange contracts or other derivative instruments to reduce our exposure to this risk. In the future, we may use such foreign currency exchange contracts and other derivative instruments to reduce our foreign currency exposure 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.

116

Effects 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. Energy payments pursuant to the PPAs for the Mammoth complex (after April 2012), the Ormesa project (after April 2012) and the Heber 1 and 2 power plants (after April 2012) will change because of our power purchasers’ underlying short run avoided costs. To the extent that inflation causes an increase in those short run avoided costs, higher energy payments could have an offsetting impact to any inflation-driven increase in our expenses. Similarly, the energy payments pursuant to the PPAs for the Brady power plant, the Steamboat 2/3 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. Lease payments are generally fixed, while royalty payments are generally determined as a percentage of revenues and therefore are not significantly impacted by inflation. Overall, we believe that the impact of inflation on our business will not be significant.

Contractual Obligations and Commercial Commitments

The following tables set forth our material contractual obligations as of December 31, 2009, (in thousands):


	Payments Due By Period
	Remaining
	Total		2010		2011		2012		2013		2014		Thereafter

Principal of long-term liabilities	$	634,042	$	61,843	$	183,021	$	50,288	$	52,775	$	55,897	$	230,218
Interest on long-term liabilities ⁽¹⁾		179,968		34,238		30,139		26,902		23,606		20,111		44,972
Future minimum operating lease payments		87,754		7,567		8,061		8,199		8,062		8,647		47,218
Benefits upon retirement ⁽²⁾		14,021		3,161		1,040		587		717		643		7,873
Asset retirement obligation		14,238		—		—		—		—		—		14,238

	$	930,023	$	106,809	$	222,261	$	85,976	$	85,160	$	85,298	$	344,519


⁽¹⁾		Interest on the OFC Senior Secured Notes due in 2020 is fixed at a rate of 8 1 / 4 %. Interest on the OrCal Senior Secured Notes due in 2020 is fixed at a rate of 6.21%. Interest on the Orzunil Senior Loans due in 2010 and 2011 is fixed at rates of 10.300% and 11.775%, respectively. Interest on the Olkaria III loan due in 2018 is fixed for $77.0 million at a rate of 6.9% and variable on the remaining balance. Interest on the Amatitlan Loan due in 2016 is fixed at a rate of 9.83%. Interest on the Ormat Industries notes is fixed at the rate of 7.50%. Interest on the remaining debt is variable (based primarily on changes in LIBOR rates). Accordingly, for purposes of the above calculation of interest payments pertaining to variable rate debt, the methodology used to determine future LIBOR rates was the use of 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 retirement date. These amounts do not include amounts that might be paid to employees that will cease working with us before reaching their normal retirement age.

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, 2009, total obligations related to such supplier agreements were approximately $42.1 million (out of which approximately $29.4 million relate to construction-in-process). All such obligations are payable in 2009.

The above table does not reflect unrecognized tax benefits of $4.9 million the timing of which is uncertain. Refer to Note 16 to our Consolidated Financial Statements set forth in Item 8 of this annual report for additional

117

discussion of unrecognized tax benefits. The above table also does not reflect a liability associated with sale of tax benefits of $73.2 million the timing of which is uncertain. Refer to Note 11 of our consolidated financial statements as set forth in Item 8 of this annual report for additional discussion of this liability.

Concentration of Credit Risk

Our credit risk is currently concentrated with a limited number of major customers: Southern California Edison, HELCO, and Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.). 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.

Southern California Edison accounted for 21.0%, 27.6% and 31.9% of our total revenues for the three years ended December 31, 2009, 2008 and 2007, respectively. Southern California Edison is also the power purchaser and revenue source for our Mammoth project, which we account for separately under the equity method of accounting.

HELCO accounted for 6.3%, 16.7% and 14.6% of our total revenues for the three years ended December 31, 2009, 2008 and 2007, respectively.

Sierra Pacific Power Company and Nevada Power Company accounted for 12.9%, 12.6% and 10.9% of our total revenues for the three years ended December 31, 2009, 2008 and 2007, respectively.

Government Grants and Tax Benefits

The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies under the recently enacted ARRA. We are permitted to claim 30% of the cost of each new geothermal power plant in the United States as an ITC against our federal income taxes. Alternatively, we are permitted to claim a PTC, which in 2009 was 2.1 cents per kWh and which is 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 project 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 we claim the PTC or the ITC, we are also permitted to depreciate most of the plant for tax purposes over five years on an accelerated basis, meaning that more of the cost maybe deducted in the first few years than during the remainder of the depreciation period. If we claim the ITC, our “tax basis” in the plant that we can recover through depreciation must be reduced by half of the tax credit; if we claim a PTC; there is no reduction in the tax basis for depreciation. Companies that begin construction on, or place qualifying renewable energy facilities in service, during 2009 or 2010 may choose to apply for a cash grant from the U.S. Department of Treasury in an amount equal to the ITC. Under the ARRA, the U.S. Department of 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.

Production of electricity from geothermal resources is also supported under the new “Temporary Program For Rapid Deployment of Renewable Energy and Electric Power Transmission Projects” established with the DOE as part of the DOE’s existing Innovative Technology Loan Guarantee Program. The new program: (i) extends the scope of the existing federal loan guarantee program to cover renewable energy projects, renewable energy component manufacturing facilities, and electricity transmission projects that embody established commercial, as well as innovative, technologies; and (ii) provides an appropriation to cover the “credit subsidy costs” of such projects (meaning the estimated average costs to the federal government from issuing the loan guarantee, equivalent to a lending bank’s loan loss reserve).

To be eligible for a guarantee under the new program, a supported project must break ground, and the guarantee must be issued, by September 30, 2011. A project supported by the federal guarantee under the new program must pay prevailing federal wages.

Based on the appropriation of $6 billion dollars to pay the credit subsidy costs of guarantees issued under the new program, it is likely that between $60 billion to $120 billion of financing (assuming average subsidy requirements between 10% and 5%, respectively) will be available to eligible projects, including geothermal power plants.

118

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 is subject to reduced Israeli income tax rates, which will not exceed 25% for an additional five years. Ormat Systems is 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. These benefits are subject to certain conditions, including among other things, that all transactions between Ormat Systems and our affiliates are at arms 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 Israeli Tax Authorities in order to maintain the tax benefits. In addition, as an industrial company, Ormat Systems is entitled to accelerated depreciation on equipment used for its industrial activities. Under the provisions of certain tax regulations published in Israel in 2005, industrial companies whose operations are mostly “Eligible Operations” are entitled to claim accelerated depreciation at the rate of 100% on machinery and equipment acquired from July 1, 2005 to December 31, 2006. Accelerated depreciation is to be claimed over two years. In the year in which the equipment was acquired, the regular depreciation rate is to be claimed with the remainder to be claimed in the second year. Under the provisions of certain tax regulations published in Israel in July 2008, industrial companies whose operations are mostly “Eligible Operations” are entitled to claim accelerated depreciation at the rate of 50% on machinery and equipment acquired from June 1, 2008 to May 31, 2009 and placed in service at the later of six months after acquisition or before May 31, 2009.


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.

119


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			121
Consolidated Financial Statements as of December 31, 2009 and 2008 and for Each of the Three Years in the Period Ended December 31, 2009:
Consolidated Balance Sheets			122
Consolidated Statements of Operations and Comprehensive Income			123
Consolidated Statements of Stockholders’ Equity			124
Consolidated Statements of Cash Flows			125
Notes to Consolidated Financial Statements			126

Financial statements of one 50% owned entity have been omitted because the registrant’s proportionate share of the income from continuing operations before income taxes is less than 20% of the respective consolidated amount, and the investment in and advances to this entity are less than 20% of consolidated total assets.

120

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, of stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Ormat Technologies, Inc. and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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, 2009, 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.

As discussed in Note 1 to the consolidated financial statements, the Company has restated its 2008 consolidated financial statements to correct an error.

As discussed in Note 11 to the consolidated financial statements, the Company changed the manner in which it accounts for noncontrolling interests in 2009. In addition, as discussed in Note 16 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions in 2007.

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 8, 2010

121

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2009		2008 (As Restated)
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	46,307	$	34,393
Restricted cash, cash equivalents and marketable securities		40,955		24,439
Receivables:
Trade		53,423		49,839
Related entity		441		338
Other		7,884		15,654
Due from Parent		422		1,085
Inventories		15,486		13,724
Costs and estimated earnings in excess of billings on uncompleted contracts		14,640		6,982
Deferred income taxes		3,617		3,003
Prepaid expenses and other		12,080		16,222

Total current assets		195,255		165,679
Long-term marketable securities		652		1,994
Restricted cash, cash equivalents and marketable securities		2,512		2,951
Unconsolidated investments		35,527		30,559
Deposits and other		18,314		16,876
Deferred income taxes		22,532		13,965
Property, plant and equipment, net		998,693		940,635
Construction-in-process		518,595		394,224
Deferred financing and lease costs, net		20,940		19,240
Intangible assets, net		41,981		44,853

Total assets	$	1,855,001	$	1,630,976


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	73,993	$	103,336
Billings in excess of costs and estimated earnings on uncompleted contracts		3,351		15,670
Current portion of long-term debt:
Limited and non-recourse		19,191		6,676
Full recourse		12,823		—
Senior secured notes (non-recourse)		20,227		20,085
Due to Parent, including current portion of notes payable to Parent		10,018		16,616

Total current liabilities		139,603		162,383
Long-term debt, net of current portion:
Limited and non-recourse		129,152		7,814
Full recourse		77,177		—
Revolving credit lines with banks (full recourse)		134,000		100,000
Senior secured notes (non-recourse)		231,872		252,060
Notes payable to Parent		—		9,600
Liability associated with sale of tax benefits		73,246		113,327
Deferred lease income		72,867		74,427
Deferred income taxes		44,530		29,627
Liability for unrecognized tax benefits		4,931		3,425
Liabilities for severance pay		18,332		17,640
Asset retirement obligation		14,238		13,438
Other long-term liabilities		3,358		—

Total liabilities		943,306		783,741

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 and 45,353,120 shares issued and outstanding, respectively		46		45
Additional paid-in capital		709,354		701,273
Retained earnings		196,950		138,241
Accumulated other comprehensive income		622		645

		906,972		840,204
Noncontrolling interest		4,723		7,031

Total equity		911,695		847,235

Total liabilities and equity	$	1,855,001	$	1,630,976

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


	Year Ended December 31,
	2009			2008 (As Restated)			2007
	(In thousands, except per share data)

Revenues:
Electricity	$	255,855		$	252,256		$	215,969
Product		159,389			92,577			79,950

Total revenues		415,244			344,833			295,919

Cost of revenues:
Electricity		180,156			170,053			148,698
Product		112,450			72,755			68,036

Total cost of revenues		292,606			242,808			216,734

Gross margin		122,638			102,025			79,185
Operating expenses:
Research and development expenses		10,502			4,595			3,663
Selling and marketing expenses		14,584			10,885			10,645
General and administrative expenses		26,412			25,938			21,416
Write-off of unsuccessful exploration activities		2,367			9,828			—

Operating income		68,773			50,779			43,461
Other income (expense):
Interest income		639			3,118			6,565
Interest expense, net		(16,241	)		(14,945	)		(29,745	)
Foreign currency translation and transaction gains (losses)		1,107			(7,721	)		(1,339	)
Impairment of auction rate securities		(279	)		(4,195	)		(2,020	)
Income attributable to sale of tax benefits		15,515			18,118			6,488
Gain from extinguishment of liability		13,348			—			—
Other non-operating income, net		479			771			890

Income before income taxes and equity in income of investees		83,341			45,925			24,300
Income tax provision		(16,924	)		(4,358	)		(1,822	)
Equity in income of investees, net		2,136			1,725			4,742

Net income		68,553			43,292			27,220
Net loss attributable to noncontrolling interest		298			316			156

Net income attributable to the Company’s stockholders	$	68,851		$	43,608		$	27,376

Comprehensive income:
Net income	$	68,553		$	43,292		$	27,220
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment		842			(885	)		—
Amortization of unrealized gains in respect of derivative instruments
designated for cash flow hedge		(254	)		(293	)		(326	)
Change in unrealized gains or losses on marketable securities available-for-sale		594			435			(590	)

Comprehensive income		69,735			42,549			26,304
Comprehensive loss attributable to noncontrolling interest		298			316			156

Comprehensive income attributable to the Company’s stockholders	$	70,033		$	42,865		$	26,460

Earnings per share attributable to the Company’s stockholders — basic and diluted
Basic	$	1.52		$	0.99		$	0.71

Diluted	$	1.51		$	0.98		$	0.70

Weighted average number of shares used in computation of earnings
per share attributable to the Company’s stockholders:
Basic		45,391			44,182			38,762

Diluted		45,533			44,298			38,880

Dividend per share declared	$	0.25		$	0.20		$	0.22

The accompanying notes are an integral part of the consolidated financial statements.

123

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY


	The Company’s Stockholders’ Equity
										Accumulated
					Additional					Other
	Common Stock				Paid-in		Retained			Comprehensive						Noncontrolling			Total
	Shares		Amount		Capital		Earnings			Income			Total			Interest			Equity
	(In thousands, except per share data)

Balance at December 31, 2006		38,102	$	38	$	353,399	$	85,053		$	2,304		$	440,794		$	67		$	440,861
Stock-based compensation		—		—		3,763		—			—			3,763			—			3,763
Cash dividend declared, $0.22 per share		—		—		—		(8,556	)		—			(8,556	)		—			(8,556	)
Issuance of shares of common stock in a block trade transaction		3,000		2		137,242		—			—			137,244			—			137,244
Issuance of unregistered shares of common stock to the Parent in a private placement		381		1		17,499		—						17,500			—			17,500
Exercise of options by employees		47		—		743		—			—			743			—			743
Tax benefit on exercise of options by employees		—		—		463		—			—			463			—			463
Increase in noncontrolling interest due to sale of equity interest in OPC LLC		—		—		—		—			—			—			4,838			4,838
Cumulative adjustment from adoption of FIN No. 48		—		—		—		(328	)		—			(328	)		—			(328	)
Net income		—		—		—		27,376			—			27,376			(156	)		27,220
Other comprehensive loss, net of related taxes:
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $204,000)		—		—		—		—			(326	)		(326	)		—			(326	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $367,000)		—		—		—		—			(590	)		(590	)		—			(590	)

Balance at December 31, 2007		41,530		41		513,109		103,545			1,388			618,083			4,749			622,832
Stock-based compensation		—		—		4,444		—			—			4,444			—			4,444
Cash dividend declared, $0.20 per share		—		—		—		(8,912	)		—			(8,912	)		—			(8,912	)
Issuance of shares of common stock in a block trade transaction		3,100		3		149,652		—			—			149,655			—			149,655
Issuance of unregistered shares of common stock to the Parent in a private placement		694		1		33,314		—			—			33,315			—			33,315
Exercise of options by employees		29		—		602		—			—			602			—			602
Tax benefit on exercise of options by employees		—		—		152		—			—			152			—			152
Increase in noncontrolling interest due to sale of equity interest in OPC LLC																	2,598			2,598
Net income (loss) (as restated)		—		—		—		43,608			—			43,608	*		(316	)		43,292	*
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment		—		—		—		—			(885	)		(885	)		—			(885	)
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $181,000)		—		—		—		—			(293	)		(293	)		—			(293	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $260,000)		—		—		—		—			435			435			—			435

Balance at December 31, 2008 (as restated)		45,353		45		701,273		138,241			645			840,204			7,031			847,235
Stock-based compensation		—		—		5,755		—			—			5,755			—			5,755
Cumulative effect of adopting the other-than-temporary
impairment standard as of April 1, 2009 (net of related tax of $650,000)		—		—		—		1,205			(1,205	)		—			—			—
Cash dividend declared, $0.25 per share		—		—		—		(11,347	)		—			(11,347	)		—			(11,347	)
Exercise of options by employees		78		1		1,241		—			—			1,242			—			1,242
Acquisition of noncontrolling interest		—		—		1,085		—			—			1,085			(2,010	)		(925	)
Net income (loss)		—		—		—		68,851			—			68,851			(298	)		68,553
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment		—		—		—		—			842			842			—			842
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $158,000)		—		—		—		—			(254	)		(254	)		—			(254	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $339,000)		—		—		—		—			594			594			—			594

Balance at December 31, 2009		45,431	$	46	$	709,354	$	196,950		$	622		$	906,972		$	4,723		$	911,695

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,
	2009			2008 (As Restated)			2007
	(In thousands)

Cash flows from operating activities:
Net income	$	68,553		$	43,292		$	27,220
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		64,376			60,128			50,482
Accretion of asset retirement obligation		1,060			1,069			1,105
Stock-based compensation		5,755			4,444			3,763
Amortization of deferred lease income		(2,685	)		(2,685	)		(2,685	)
Income attributable to sale of tax benefits, net of interest expense		(8,322	)		(10,850	)		(3,726	)
Equity in income of investees		(2,136	)		(1,725	)		(4,742	)
Impairment of auction rate securities		279			4,195			2,020
Loss on disposal of property , plant and equipment		2,469			—			—
Write-off of unsuccessful exploration activities		2,367			9,828			—
Loss from sell of auction rate securities		194			—			—
Return on investment in unconsolidated investments		—			2,435			9,787
Changes in unrealized loss in respect of derivative instruments, net		—			—			199
Gain on severance pay fund asset		(468	)		(324	)		(722	)
Gain from extinguishment of liability		(13,348	)		—			—
Deferred income tax provision (benefit)		3,957			3,241			(4,930	)
Liability for unrecognized tax benefits		1,506			(188	)		1,576
Deferred lease revenues		1,125			914			—
Other		—			(423	)		—
Changes in operating assets and liabilities:
Receivables		3,921			(6,327	)		(13,788	)
Costs and estimated earnings in excess of billings on uncompleted contracts		(7,658	)		(3,374	)		7,608
Inventories		(1,762	)		(3,412	)		(2,909	)
Prepaid expenses and other		4,146			(9,163	)		(2,148	)
Deposits and other		(49	)		(224	)		302
Accounts payable and accrued expenses		(2,081	)		13,521			(12,212	)
Due from/to related entities, net		(103	)		47			494
Billings in excess of costs and estimated earnings on uncompleted contracts		(12,319	)		10,852			(985	)
Liabilities for severance pay		692			2,439			1,823
Due from/to Parent		1,303			(761	)		1,193

Net cash provided by operating activities		110,772			116,949			58,725

Cash flows from investing activities:
Return of investment in unconsolidated investments		—			316			2,500
Marketable securities, net		1,580			12,594			78,722
Net change in restricted cash, cash equivalents and marketable securities		(15,873	)		5,614			20,117
Capital expenditures		(270,623	)		(416,606	)		(216,358	)
Cash paid for acquisition		(261	)		—			—
Intangible asset acquired		—			—			(1,150	)
Increase in severance pay fund asset, net of payments made to retired employees		(921	)		(1,034	)		(269	)
Repayment from unconsolidated investment		62			125			127

Net cash used in investing activities		(286,036	)		(398,991	)		(116,311	)

Cash flows from financing activities:
Proceeds from public offerings, net of issuance costs		—			149,655			137,244
Proceeds from issuance of unregistered shares of common stock to the Parent		—			33,315			17,500
Proceeds from long-term loans		237,000			—			—
Proceeds from exercise of options by employees		1,242			602			743
Proceeds from the sale of limited liability company interest in OPC LLC, net of transaction costs		—			63,029			69,200
Purchase of limited liability company interest in OPC LLC		(18,500	)		—			—
Purchase of OFC Senior Secured Notes		—			(1,321	)		—
Proceeds from sale of interest rate caps		—			—			277
Proceeds from revolving credit lines with banks		1,152,500			100,000			—
Repayment of revolving credit lines with banks		(1,118,500	)		—			—
Repayments of long-term debt
Parent		(16,600	)		(31,647	)		(31,647	)
Other		(33,193	)		(34,142	)		(49,537	)
Repayment of capital notes to Parent		—			—			(50,665	)
Deferred debt issuance costs		(5,566	)		(1,293	)
Cash dividends paid		(11,347	)		(8,912	)		(8,556	)

Net cash provided by financing activities		187,036			269,286			84,559

Effect of exchange rate changes on cash and cash equivalents		142			(78	)		—

Net change in cash and cash equivalents		11,914			(12,834	)		26,973
Cash and cash equivalents at beginning of year		34,393			47,227			20,254

Cash and cash equivalents at end of year	$	46,307		$	34,393		$	47,227

Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest, net of interest capitalized	$	369		$	6,220		$	38,068

Income taxes, net	$	5,098		$	5,033		$	6,990

Supplemental non-cash investing and financing activities:
Increase (decrease) in accounts payable related to purchases of property, plant and equipment	$	(23,890	)	$	13,368		$	18,665

Decrease in asset retirement cost and asset retirement obligation	$	(260	)	$	(645	)	$	(4,923	)

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 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, Nicaragua, and New Zealand. 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 PPAs (“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 as of December 31, 2009.

Cash dividends

During the years ended December 31, 2009, 2008 and 2007, the Company’s Board of Directors declared, approved, and authorized the payment of cash dividends in the aggregate amount of $11.3 million ($0.25 per share), $8.9 million ($0.20 per share), and $8.6 million ($0.22 per share) respectively. Such dividends were paid in the years declared.

Shelf registration statements and issuance of stock

On October 26, 2007, the Company completed a sale of 3,000,000 shares of common stock to Lehman Brothers Inc. in a block trade at a price of $45.90 per share (net of underwriting fees and commissions), under a universal shelf registration statement on Form S-3, which was declared effective by the Securities and Exchange Commission (“SEC”) on January 31, 2006. Net proceeds to the Company after deducting underwriting fees and commissions and offering expenses associated with the offering were approximately $137.2 million.

On October 26, 2007, the Company completed an unregistered sale of 381,254 shares of common stock to the Parent at a price of $45.90 per share. The proceeds from the unregistered sale were approximately $17.5 million. The shares of common stock issued in the unregistered sale have not been and will not be registered under the Securities Act of 1933, as amended, or any state securities laws, and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act of 1933, as amended.

A portion of the proceeds from the October 26, 2007 block trade and the unregistered sale of shares was used to repay a capital note owed to the Parent in the amount of $50.7 million on December 3, 2007.

On January 8, 2008, the Company completed an unregistered sale of 693,750 shares of common stock to the Parent, at a price of $48.02 per share. The proceeds from the unregistered sale were approximately $33.3 million. The shares of common stock issued in the unregistered sale have not been and will not be registered under the Securities Act of 1933, as amended, or any state securities laws, and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act of 1933, as amended.

On May 14, 2008, the Company completed a sale of 3,100,000 shares of common stock to Lehman Brothers Inc. in a block trade at a price of $48.36 per share (net of underwriting fees and commissions), under the shelf registration statement mentioned above. Net proceeds to the Company after deducting underwriting fees and commissions and offering expenses associated with the offering were approximately $149.7 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On September 17, 2008, the Company filed a universal shelf registration statement on Form S-3, which was declared effective by the SEC on October 2, 2008. The shelf registration statement replaces the Company’s former shelf registration statement, which would have expired on January 31, 2009, and provides the Company with the opportunity to issue various types of securities, including debt securities, common stock, warrants, and units of the Company, from time to time, in one or more offerings up to a total dollar amount of $1.5 billion. Pursuant to the shelf registration statement, the Company may periodically offer one or more of the registered securities in amounts, at prices, and on terms to be announced when, and if, the securities are offered. At the time any offering is made under the shelf registration statement, the offering specifics will be set out in a prospectus supplement.

Rounding

Dollar amounts, except per share data, in the notes to these financial statements are rounded to the closest $1,000, unless otherwise indicated.

Restatement

Through the third quarter of 2009, the Company accounted for exploration and development costs using an accounting method that is analogous to the full cost method used in the oil and gas industry. Under that method, the Company capitalized costs incurred in connection with the exploration and development of geothermal resources on an “area-of-interest” basis. Each area of interest included a number of potential projects in the state of Nevada that were planned to be operated together with the same operation and maintenance team. Impairment tests were performed on an area-of-interest basis rather than at a single site. Under this methodology, costs associated with projects that the Company has determined are not economically feasible remained capitalized as long as the area-of-interest was not subject to impairment.

Following a periodic review performed by the Securities and Exchange Commission (“SEC”) Staff, the Company concluded that this accounting treatment was inappropriate in certain respects and have restated the 2008 consolidated financial statements to write-off capitalized costs for projects the Company has determined are not economically feasible in the period such determination was made. Refer to a more detailed discussion of our accounting policy in “Exploration and development costs” below.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The effect of the restatement on the financial statements as of December 31, 2008 and for the year ended December 31, 2008 is as follows:

Consolidated balance sheet data at December 31, 2008:


								Application
	As					As Restated Before		of New
	Originally		Restatement			Application of New		Accounting			As
	Reported		Adjustment			Accounting Standard		Standard			Restated
	(Dollars in thousands)

Assets
Construction-in-process	$	404,052	$	(9,828	)	$	394,224	$	—		$	394,224
Deferred financing and lease costs, net		16,127		—			16,127		3,113			19,240

Total assets	$	1,637,691	$	(9,828	)	$	1,627,863	$	3,113		$	1,630,976

Liabilities and equity
Liability associated with sale of tax benefits	$	—	$	—		$	—	$	113,327		$	113,327
Deferred income taxes		33,231		(3,604	)		29,627		—			29,627

Total liabilities		674,018		(3,604	)		670,414		113,327			783,741

Minority interest		117,245		—			117,245		(117,245	)		—

Equity:
The Company’s stockholders’ equity:
Common stock		45		—			45		—			45
Additional paid-in capital		701,273		—			701,273		—			701,273
Retained earnings		144,465		(6,224	)		138,241		—			138,241
Accumulated other comprehensive income		645		—			645		—			645

		846,428		(6,224	)		840,204		—			840,204
Noncontrolling interest		—		—			—		7,031			7,031

Total equity		846,428		(6,224	)		840,204		7,031			847,235

Total liabilities and equity	$	1,637,691	$	(9,828	)	$	1,627,863	$	3,113		$	1,630,976

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Consolidated statements of operations and comprehensive income data for the year ended December 31, 2008:


							As restated
							Before			Application
	As						Application of			of New
	Originally			Restatement			New Accounting			Accounting			As
	Reported			Adjustment			Standard			Standard			Restated
	(Dollars in thousands)

Write-off of unsuccessful exploration activities	$	—		$	(9,828	)	$	(9,828	)	$	—		$	(9,828	)

Operating income		60,607			(9,828	)		50,779			—			50,779

Other income (expense):
Interest income		3,118			—			3,118			—			3,118
Interest expense, net		(7,677	)		—			(7,677	)		(7,268	)		(14,945	)
Foreign currency translation and transaction losses		(7,721	)		—			(7,721	)		—			(7,721	)
Income attributable to sale of tax benefits		—			—			—			18,118			18,118
Other non-operating expense, net		(3,424	)		—			(3,424	)		—			(3,424	)

Income before income taxes, minority interest, and equity in income of investees		44,903			(9,828	)		35,075			10,850			45,925
Income tax provision		(7,962	)		3,604			(4,358	)		—			(4,358	)
Minority interest		11,166			—			11,166			(11,166	)		—
Equity in income of investees, net		1,725			—			1,725			—			1,725

Net income		49,832			(6,224	)		43,608			(316	)		43,292
Net loss attributable to noncontrolling interest		—			—			—			316			316

Net income attributable to the Company’s stockholders	$	49,832		$	(6,224	)	$	43,608		$	—		$	43,608

Comprehensive income:
Net income	$	49,832		$	(6,224	)	$	43,608		$	(316	)	$	43,292
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment		(885	)		—			(885	)		—			(885	)
Amortization of unrealized gains in respect of derivative								—
instruments designated for cash flow hedge		(293	)		—			(293	)		—			(293	)
Change in unrealized gains or losses on marketable								—
securities available-for-sale		435			—			435			—			435

Comprehensive income		49,089			(6,224	)		42,865			(316	)		42,549
Comprehensive loss attributable to noncontrolling interest		—			—			—			316			316

Comprehensive income attributable to the Company’s stockholders	$	49,089		$	(6,224	)	$	42,865		$	—		$	42,865

The effect of the restatement on the consolidated financial statements for the three- month period ended December 31, 2008 is disclosed in Note 21. The Company also revised its consolidated financial statements as of and for the three-month period ended September 30, 2009 to reduce net income by approximately $1.5 million to expense previously capitalized exploration and development costs related to a project which the Company determined in the third quarter of 2009 would not support commercial operations. The effect of the revision is disclosed in Note 21.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Reclassification

Certain comparative figures have been reclassified to conform to the current year presentation (see Note 6).

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 in investments accounted for under the equity method have been reflected as “Equity in income of investees, net” on the Company’s consolidated statements of operations and comprehensive income.

Cash and cash equivalents

The Company considers all highly liquid instruments, with an original maturity of three months or less, to be cash equivalents.

Auction rate securities

At December 31, 2009 and 2008, all of the Company’s investments in auction rate securities were classified as available-for-sale securities and as a result, were reported at their fair value which was determined based on the factors discussed in Note 5.

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 reserve, 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 and are not auction rate securities 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 5). Such amounts are invested primarily in money market accounts and commercial paper with a minimum investment grade of “AA”, and auction rate securities.

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, 2009 and 2008, the Company had deposits totaling $24,561,000 and $23,120,000, in seven U.S. financial institutions that were federally insured up to $250,000 per account (after December 31, 2013, the deposits will be insured up to $100,000 per account). At December 31, 2009 and 2008, the Company’s deposits in foreign countries of approximately $35,095,000 and $20,377,000, respectively, were not insured.

At December 31, 2009 and 2008, accounts receivable related to operations in foreign countries amounted to approximately $30,761,000 and $14,867,000, respectively. At December 31, 2009 and 2008, accounts receivable

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

from the Company’s major customers that have generated 10% or more of its revenues (see Note 17) amounted to approximately 61% and 45%, respectively, of the Company’s accounts receivable.

Southern California Edison Company (“SCE”) accounted for 21.0%, 27.6%, and 31.9% of the Company’s total revenues for the years ended December 31, 2009, 2008, and 2007, respectively. SCE is also the power purchaser and revenue source for the Mammoth complex, which is accounted for separately under the equity method.

Hawaii Electric Light Company accounted for 6.3%, 16.7%, and 14.6% of the Company’s total revenues for the years ended December 31, 2009, 2008, and 2007, respectively.

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 12.9%, 12.6%, and 10.9% of the Company’s total revenues for the years ended December 31, 2009, 2008, and 2007, respectively.

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, which amount was not significant at December 31, 2009 and 2008.

Deposits and other

Deposits and other consist primarily of performance bonds for construction projects, a long-term insurance contract and derivative instruments.

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. The geothermal power plant in Nicaragua is to be fully depreciated over the period that the plant is operated by the Company (see Note 6). 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

During the second quarter of 2007, the Company revised the estimated useful life of certain of its power plants from 20 or 25 years to 30 years to reflect the expected period these plants will be utilized. The change in estimated useful life has been accounted for on a prospective basis effective April 1, 2007. The impact of this change in estimated useful life was an increase in net income and earnings per share of $771,000 and $0.02, respectively, in

131

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the year ended December 31, 2007. 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 $27,395,000, $21,312,000 and $6,835,000 for the years ended December 31, 2009, 2008 and 2007, respectively.

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 on the consolidated statements of operations and comprehensive income. Such costs were immaterial during the years ended December 31, 2009, 2008, and 2007. It normally takes one to two 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 on the consolidated statements of operations and comprehensive income. 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 on the consolidated statements of operations and comprehensive income.

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.

All exploration and development costs that are being capitalized, including the up-front bonus payments made to secure land leases, will be depreciated over their estimated useful lives when the related geothermal power plant is substantially complete and ready for use. A geothermal power plant is substantially complete and ready for use when electricity generation commences.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. Accumulated amortization related to deferred financing costs amounted to $9,924,000 and $6,922,000 at December 31, 2009 and 2008, respectively. Amortization expense for the years ended December 31, 2009, 2008 and 2007 amounted to $3,060,000, $1,499,000 and $1,718,000, respectively. In the year ended December 31, 2009 an amount of $834,000 was written-off as a result of the extinguishment of a liability.

Deferred transaction costs relating to the Puna operating lease (see Note 10) 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. Accumulated amortization related to deferred lease costs amounted to $853,000 and $669,000 at December 31, 2009 and 2008, respectively. Amortization expense for each of the years ended December 31, 2009, 2008, and 2007 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, construction-in-process, PPAs, and unconsolidated investments for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Factors which could trigger an impairment include, among others, significant underperformance relative to historical or projected future operating results, significant changes in the Company’s use of assets or its overall business strategy, negative industry or economic trends, a determination that an exploration project will not support commercial operations, a determination that a suspended project is not likely to be completed, a significant increase in costs necessary to complete a project, legal factors relating to its business or when it concludes that it is more likely than not that an asset will be disposed of or sold.

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

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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 no impairment exists for long-lived assets; however, estimates as to the recoverability of such assets may change based on revised circumstances.

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 forward exchange contracts, interest rate swaps, and interest rate caps to minimize significant fluctuation in cash flows and/or earnings that are caused by 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 which is using a functional currency other than the U.S. dollar, the cumulative translation effects are included in “accumulated other comprehensive income” in the consolidated balance sheets.

Comprehensive income reporting

Comprehensive income includes net income plus other comprehensive income, 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 power plants owned and operated by the Company; and (ii) geothermal and recovered energy power plant equipment engineering, sale, construction and installation, and operating services.

Revenues related to the sale of electricity from geothermal and recovered energy power plants and capacity payments are recorded based upon output delivered and capacity provided at rates specified under relevant contract terms. The PPAs are exempt from derivative treatment due to the normal purchase and sale exception. For PPAs agreed to, modified, or acquired in business combinations on or after July 1, 2003 revenues related to the lease element of the PPAs are included in electricity revenues. The lease element of the PPAs is determined in accordance with the revenue arrangements with multiple deliverables guidance , which requires that revenues be allocated to the

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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 PPA.

The components of electricity revenues are as follows:


	Year Ended December 31,
	2009		2008		2007
	(Dollars in thousands)

Energy and capacity	$	95,942	$	100,303	$	90,827
Lease portion of energy and capacity		157,228		149,268		122,457
Lease income		2,685		2,685		2,685

	$	255,855	$	252,256	$	215,969

The components of cost of electricity revenues are as follows:


	Year Ended December 31,
	2009		2008		2007
	(Dollars in thousands)

Energy and capacity	$	94,347	$	94,577	$	82,620
Lease portion of energy and capacity		80,567		70,234		60,835
Lease income		5,242		5,242		5,243

	$	180,156	$	170,053	$	148,698

Revenues from engineering, operating services, and parts and product sales are recorded upon providing the service or delivery of the products and parts. Revenues from the supply and/or construction of geothermal and recovered energy 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.

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, 2009, 2008, and 2007.

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 U.S. Department of Energy are offset against the related research and development expenses. Such grants amounted to $1,330,000, $554,000 and $0 for the years ended December 31, 2009, 2008, and 2007, respectively.

Stock-based compensation

The Company accounts for stock-based compensation using the fair value method whereby compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the requisite employee service period (generally the vesting period of the grant).

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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 more likely than not expected to be realized. 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 (see Note 16).

Earnings per share

Basic earnings per share attributable to the Company’s stockholders (“earnings per share”) is computed by dividing net income 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 stock options granted to employees of the Company in the Parent’s stock are not dilutive to the Company’s earnings per share in any year.

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,
	2009		2008		2007
	(In thousands)

Weighted average number of shares used in computation of basic earnings per share		45,391		44,182		38,762
Add:
Additional shares from the assumed exercise of stock-based awards		142		116		118

Weighted average number of shares used in computation of diluted earnings per share		45,533		44,298		38,880

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 antidilutive was 1,161,870, 875,648, and 661,312, respectively, for the years ended December 31, 2009, 2008, and 2007.

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 completion method, asset retirement obligations, and the provision for income taxes.

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New accounting pronouncements

New accounting pronouncements effective in the year ended December 31, 2009

Fair Value Measurements

Effective January 1, 2008, the Company adopted the new accounting guidance on fair value measurements issued by the Financial Accounting Standards Board (“FASB”). This new guidance defines fair value, establishes a framework for measuring fair value under U.S. GAAP, and expands disclosures about fair value measurements. In February 2008, the FASB deferred the effective date for the new accounting guidance for all non-financial assets and liabilities that are recognized and disclosed at fair value on a nonrecurring basis in the financial statements until January 1, 2009. The adoption of the new guidance for all non-financial assets and liabilities, effective January 1, 2009 did not have a material impact on the Company’s consolidated financial statements.

Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the FASB issued new accounting guidance for noncontrolling interests in a subsidiary and for the deconsolidation of a subsidiary. The guidance clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of this guidance are applied prospectively. The Company adopted the guidance on January 1, 2009 and amended its presentation and disclosures accordingly (see “Restatement” below and Note 11).

Business Combinations

In December 2007, the FASB issued new accounting guidance on business combinations. The new guidance revises the method of accounting for a number of aspects of business combinations, including acquisition costs, contingencies (including contingent assets, contingent liabilities and contingent purchase price), the impacts of partial and step-acquisitions (including the valuation of net assets attributable to non-acquired minority interests), and post acquisition exit activities of acquired businesses. The adoption of the new guidance by the Company on January 1, 2009 did not have an impact on its consolidated financial statements; however, it could impact future transactions entered into by the Company.

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the FASB issued new accounting guidance on disclosures about derivative instruments and hedging activities. The guidance requires companies with derivative instruments to disclose information that should enable financial statement users to understand how and why a company uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect a company’s financial position, financial performance, and cash flows. The required disclosures include the fair value of derivative instruments and their gains or losses in tabular format, information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the company’s strategies and objectives for using derivative instruments. The adoption of the new guidance by the Company on January 1, 2009 did not have an impact on the Company’s financial statements.

Recognition and Presentation of Other-Than-Temporary Impairments

In April 2009, the FASB issued new accounting guidance for recognition and presentation of other-than-temporary impairments of debt securities. It is intended to bring greater consistency to the timing of impairment recognition, and provide greater clarity to investors about the credit and noncredit components of impaired debt securities that are not expected to be sold. The measure of impairment remains fair value. The guidance also requires increasing disclosures regarding expected cash flows, credit losses, and an aging of securities with

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unrealized losses. The effect of the Company’s adoption of this new accounting guidance on April 1, 2009 is disclosed in Note 5.

Subsequent Events

In May 2009, the FASB issued new guidance on subsequent events. The guidance requires disclosures of events that occur after the balance sheet date but before the financial statements are issued. The adoption by the Company of the guidance on June 30, 2009 did not have an impact on the Company’s consolidated financial statements.

The FASB Accounting Standards Codification

In June 2009, the FASB issued the FASB Accounting Standards Codification (the “Codification”). The Codification became the single source for all authoritative U.S. GAAP recognized by the FASB to be applied for financial statements issued for periods ending after September 15, 2009 (September 30, 2009 for the Company). The Codification does not change U.S. GAAP and did not have an effect on the Company’s financial position, results of operations or liquidity.

New accounting pronouncements effective in future years

Accounting for Transfers of Financial Assets

In June 2009, the FASB issued an amendment to the accounting and disclosure requirements for transfers of financial assets. This amendment requires greater transparency and additional disclosures for transfers of financial assets and the entity’s continuing involvement with them and changes the requirements for derecognizing financial assets. In addition, this amendment eliminates the concept of a qualifying special-purpose entity (“QSPE”). This amendment is effective for financial statements issued for fiscal years beginning after November 15, 2009 (January 1, 2010 for the Company). The adoption of this amendment is not expected to have a material effect on the Company’s financial position, results of operations, or liquidity.

Consolidation Guidance for Variable Interest Entities

In June 2009, the FASB issued an amendment to the accounting and disclosure requirements for the consolidation of variable interest entities (“VIEs”). The elimination of the concept of a QSPE removes the exception from applying the consolidation guidance within this amendment. This amendment requires a company to perform a qualitative analysis when determining whether or not it must consolidate a VIE. The amendment also requires a company to continuously reassess whether it must consolidate a VIE. Additionally, the amendment requires enhanced disclosures about a company’s involvement with VIEs and any significant change in risk exposure due to that involvement, as well as how its involvement with VIEs impacts the company’s financial statements. Finally, a company will be required to disclose significant judgments and assumptions used to determine whether or not to consolidate a VIE. This amendment is effective for financial statements issued for fiscal years beginning after November 15, 2009 (January 1, 2010 for the Company). The Company is currently evaluating the potential impact, if any, of the adoption of this amendment on its consolidated financial statements.

Accounting for revenue recognition

In October 2009, the FASB issued amendments to the accounting and disclosures for revenue recognition. These amendments, effective for fiscal years beginning on or after June 15, 2010 (January 1, 2011 for the Company) with early adoption permitted, modify the criteria for recognizing revenue in multiple element arrangements and require companies to develop a best estimate of the selling price to separate deliverables and allocate arrangement consideration using the relative selling price method. Additionally, the amendments eliminate the residual method

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for allocating arrangement considerations. The Company is currently evaluating the potential impact, if any, of the adoption of this amendment on its consolidated financial statements.

Updated Disclosure for Fair Value Measurements

In January 2010, the FASB updated the fair value measurements disclosures. This update will require an entity to disclose separately the amounts of significant transfers in and out of Levels 1 and 2 fair value measurements and to describe the reasons for the transfers. In addition, information about purchases, sales, issuances and settlements are required to be presented separately (i.e., present the activity on a gross basis rather than net) in the reconciliation for fair value measurements using significant unobservable inputs (Level 3 inputs). This update clarifies existing disclosure requirements for the level of disaggregation used for classes of assets and liabilities measured at fair value, and require disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements using Level 2 and Level 3 inputs. This will become effective as of the first interim or annual reporting period beginning after December 15, 2009 (January 1, 2010 for the Company), except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 (January 1, 2011 for the Company) and for interim reporting periods within those years. The adoption of the new guidance will not have a material impact on the Company’s consolidated financial statements.


NOTE 2 —	INVENTORIES

Inventories consist of the following:


	December 31,
	2009		2008
	(Dollars in thousands)

Raw materials and purchased parts for assembly	$	7,322	$	7,649
Self-manufactured assembly parts and finished products		8,164		6,075

Total	$	15,486	$	13,724


NOTE 3 —	COST AND ESTIMATED EARNINGS ON UNCOMPLETED CONTRACTS

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


	December 31,
	2009		2008
	(Dollars in thousands)

Costs and estimated earnings incurred on uncompleted contracts	$	121,292	$	69,452
Less billings to date		110,003		78,140

Total	$	11,289	$	(8,688	)

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


	December 31,
	2009			2008
	(Dollars in thousands)

Costs and estimated earnings in excess of billings on uncompleted contracts	$	14,640		$	6,982
Billings in excess of costs and estimated earnings on uncompleted contracts		(3,351	)		(15,670	)

Total	$	11,289		$	(8,688	)

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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 4 —	UNCONSOLIDATED INVESTMENTS

Unconsolidated investments in power plant projects consist of the following:


	December 31,
	2009		2008
	(Dollars in thousands)

Mammoth	$	33,659	$	30,131
Sarulla		1,529		—
OLCL		339		428

Total	$	35,527	$	30,559

From time to time, the unconsolidated power plants make distributions to their owners. Such distributions are deducted from the investments in such power plants.

The Mammoth Complex

The Company has a 50% interest in the Mammoth complex (“Mammoth”), which is comprised of three geothermal power plants located near the city of Mammoth, California. The purchase price was less than the underlying net equity of Mammoth by approximately $9.3 million. As such, the basis difference will be amortized over the remaining useful life of the property, plant and equipment and the PPAs, which range from 12 to 17 years. The Company operates and maintains the geothermal power plants under an operation and maintenance (“O&M”) agreement. The Company’s 50% ownership interest in Mammoth is accounted for under the equity method of accounting as the Company has the ability to exercise significant influence, but not control, over Mammoth.

The unaudited condensed financial position and results of operations of Mammoth are summarized below:


	December 31,
	2009		2008
	(Dollars in thousands)

Condensed balance sheets:
Current assets	$	19,257	$	8,251
Non-current assets		64,728		69,784
Current liabilities		659		721
Non-current liabilities		3,196		3,177
Partners’ capital		80,130		74,137

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	Year Ended December 31,
	2009			2008			2007
	(Dollars in thousands)

Condensed statements of operations:
Revenues	$	19,841		$	19,175		$	17,121
Gross margin		6,181			5,180			4,281
Net income		5,993			4,868			4,198
Company’s equity in income of Mammoth:
50% of Mammoth net income	$	2,997		$	2,434		$	2,099
Plus amortization of basis difference		593			593			593

		3,590			3,027			2,692
Less income taxes		(1,363	)		(1,149	)		(1,023	)

Total	$	2,227		$	1,878		$	1,669

The Mammoth complex sells its electrical output to SCE under three separate PPAs. Under the G-1 PPA, in certain circumstances, SCE or its affiliates has a right of first refusal to acquire the plant.

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 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 (“PGE”). The project will be constructed in three phases over 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 currently negotiating certain amendments to the PPA, including an adjustment of commercial terms, and intends to proceed with the project after those amendments have become effective.

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

The Leyte Complex

The Company holds an 80% interest in Ormat Leyte Co. Ltd. (“OLCL”). OLCL is a limited partnership established for the purpose of developing, financing, operating, and maintaining geothermal power plants in Leyte Provina, the Philippines. The Company concluded that OLCL should not be consolidated pursuant to the consolidation guidance for variable interest entities. As a result of such conclusion, the Company’s 80% ownership interest in OLCL is accounted for under the equity method of accounting.

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Pursuant to a Build, Operate, and Transfer (“BOT”) agreement with PNOC-Energy Development Corporation (“PNOC”), OLCL transferred the Leyte complex’s four geothermal power generation plants to PNOC for no further consideration on September 25, 2007. The unaudited condensed financial position and results of operations of OLCL are summarized below:


	December 31,
	2009		2008
	(Dollars in thousands)

Condensed balance sheets:
Current assets	$	594	$	427
Non-current assets		33		324
Current liabilities		273		261
Stockholders’ equity		354		490


	Year Ended December 31,
	2009			2008			2007
	(Dollars in thousands)

Condensed statements of operations:
Revenues	$	—		$	—		$	11,269
Gross margin		—			—			5,433
Net income (loss)		(112	)		(190	)		2,964
Company’s equity in income (loss) of OLCL:
80% of OLCL net income (loss)	$	(91	)	$	(153	)	$	2,371
Plus amortization of deferred revenue on intercompany profit		—			—			702

Total	$	(91	)	$	(153	)	$	3,073


NOTE 5 —	FAIR VALUE OF FINANCIAL INSTRUMENTS

As described in Note 1, the provisions of the fair value measurement guidance were adopted by the Company on January 1, 2008 for financial assets and liabilities and on January 1, 2009 for non-financial assets and liabilities.

This guidance clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer 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. It 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, 2009 and 2008 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,		Fair Value at December 31, 2009
	2009		Total			Level 1		Level 2			Level 3
			(Dollars in thousands)

Assets
Current assets:
Cash equivalents (including
restricted cash accounts)	$	20,227	$	20,227		$	20,227	$	—		$	—
Derivatives ⁽¹⁾		—		91			—		91			—
Non-current assets:
Illiquid auction rate securities
including restricted cash
accounts) ($4.5 million par
value), see below ⁽²⁾		4,099		3,164			—		—			3,164
Liabilities:
Current liabilities:
Derivatives ⁽¹⁾		—		(32	)		—		(32	)		—

	$	24,326	$	23,450		$	20,227	$	59		$	3,164


	Cost or Amortized
	Cost at December 31,		Fair Value at December 31, 2008
	2008		Total			Level 1		Level 2			Level 3
	(Dollars in thousands)

Assets:
Current assets:
Cash equivalents (including
restricted cash accounts)	$	18,891	$	18,891		$	18,891	$	—		$	—
Derivatives ⁽¹⁾		—		625					625			—
Non-current assets:
Illiquid auction rate securities
including restricted cash
accounts) ($11.2 million par
value), see below ⁽²⁾		11,160		4,945			—		—			4,945
Liabilities:
Current liabilities:
Derivatives ⁽¹⁾		—		(721	)		—		(721	)		—

	$	30,051	$	23,740		$	18,891	$	(96	)	$	4,945


⁽¹⁾		Derivatives represent foreign currency forward contracts which are valued primarily based on observable inputs including forward and spot prices for currencies.

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⁽²⁾		Included in the consolidated balance sheets as follows:


	December 31,
	2009		2008
	(Dollars in thousands)

Long-term marketable securities	$	652	$	1,994
Long-term restricted cash, cash equivalents
and marketable securities		2,512		2,951

	$	3,164	$	4,945

The Company’s financial assets measured at fair value (including restricted cash accounts) at December 31, 2009 and 2008 include investments in auction rate securities and money market funds (which are included in cash equivalents). Those securities, except for the illiquid auction rate securities, are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices in an active market.

The Company’s auction rate securities are valued using Level 3 inputs. As of December 31, 2009 and 2008, all of the Company’s auction rate securities are associated with failed auctions. Such securities have par values totaling $4.5 million and $11.2 million at December 31, 2009 and 2008, respectively, all of which have been in a loss position since the fourth quarter of 2007. Historically, the carrying value of auction rate securities approximated fair value due to the frequent resetting of the interest rates. While the Company continues to earn interest on these investments at the contractual rates, the estimated market value of these auction rate securities no longer approximates par value. Due to the lack of observable market quotes on the Company’s illiquid auction rate securities, the Company utilizes valuation models that rely 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 are subject to uncertainties that are difficult to predict. Therefore, such auction rate securities have been classified as Level 3 in the fair value hierarchy.

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 the year ended December 31, 2009 and 2008:


	Year Ended December 31,
	2009			2008
	(Dollars in thousands)

Balance at beginning of year	$	4,945		$	8,367
Sale of auction rate securities		(2,005	)		—
Total unrealized gains (losses):
Included in net income		(279	)		(4,195	)
Unrealized losses included in other comprehensive
income in 2007 and expensed in 2008		—			773
Realization of unrealized losses due to sale of auction rate securities		(430	)		—
Included in other comprehensive income		933			—

Balance at end of year	$	3,164		$	4,945

Effective April 1, 2009, the Company adopted the recognition and presentation of the other-than-temporary impairments standard, which requires an entity to separate an other-than-temporary impairment of a debt security into two components when there are credit-related losses associated with the impaired security for which

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management does not have the intent to sell the security and it is not more likely than not, that it will be required to sell the security before recovery of its cost basis. For those securities, the amount of the other-than-temporary impairment related to a credit loss is recognized in earnings and reflected as a reduction in the cost basis of the security, and the amount of the other-than-temporary impairment related to other factors is recorded in other comprehensive loss with no change to the cost basis of the security. For securities for which there is an intent to sell before recovery of the cost basis, the full amount of the other-than-temporary impairment is recognized in earnings and reflected as a reduction in the cost basis of the security. Upon adoption of this standard, the Company reclassified $1.2 million (net of taxes of $0.7 million) to other comprehensive income with an offset to retained earnings related to the other-than-temporary impairment charges previously recognized in earnings. This cumulative effect adjustment relates to auction rate securities for which the Company does not have the intent to sell and will not, more likely than not, be required to sell prior to recovery of its cost basis.

For the auction rate securities for which the Company had the intent to sell upon adoption of the recognition and presentation of other than temporary impairments standard, no cumulative effect adjustment was required. The Company sold these securities ($3.9 million par value) for consideration of $0.4 million and recorded a gain of $0.3 million during the second quarter of 2009. The cumulative loss for these securities was $3.5 million as impairment charges of $3.8 million were recorded through earnings prior to the sale of the securities in the second quarter of 2009.

During the fourth quarter of 2009, the Company sold auction rate securities with a face value of $2.8 million for $1.9 million and recorded a loss of $0.6 million for this transaction. Prior to the sale of the auction rate securities, the cumulative loss for these securities was $0.8 million comprised of a credit loss of $0.3 million previously recognized in earnings and non-credit loss of $0.5 million recorded in other comprehensive income.

The amount of credit losses represents the difference between the present value of cash flows expected to be collected on these securities and the amortized cost. The credit loss was calculated as the difference between the current cash flows discounted at present value to the expected cash flows at the date of purchase. The analysis incorporates management’s best estimate of current key assumptions, including the default rate of such securities and probability of passing auction.

The change in other-than-temporary impairment losses from April 1, 2009 (the date of the adoption of the accounting standard) to December 31, 2009 was not material.

The funds invested in auction rate securities that have experienced failed auctions will not be accessible until a successful auction occurs, a buyer is found outside of the auction process, or the underlying securities reach maturity. As a result, the Company has classified those securities with failed auctions as long-term assets on the consolidated balance sheets as of December 31, 2009 and 2008.

The Company continues to monitor the market for auction rate securities and to consider the market’s impact (if any) on the fair market value of the Company’s investments. If current market conditions deteriorate further, the Company may be required to record additional impairment charges in 2010.

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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,
	2009		2008		2009		2008
	(Dollars in millions)				(Dollars in millions)

Orzunil Senior Loans	$	5.3	$	9.2	$	5.2	$	9.0
Olkaria III Loan		96.6		—		99.5		—
Amatitlan Loan		41.1		—		41.1		—
Senior Secured Notes:
Ormat Funding Corp.(“OFC”)		132.0		114.9		146.3		155.3
OrCal Geothermal Inc.(“OrCal”)		103.7		103.6		105.8		116.8
Loan from institutional investors		20.0		—		20.0		—
Parent Loan		9.7		26.1		9.6		26.2

The fair value of OFC Senior Secured Notes is determined using observable market prices as these securities are traded. The fair value of 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 market pricing curves.


NOTE 6 —	PROPERTY, PLANT AND EQUIPMENT AND CONSTRUCTION-IN-PROCESS

Construction-in-process

Construction-in-process consists of the following:


	December 31,
	2009		2008 (As Restated)
	(Dollars in thousands)

Projects under exploration and development:
Up-front bonus lease costs	$	15,867	$	17,286
Exploration and development costs		17,698		17,057
Interest capitalized		52		615

		33,617		34,958

Projects under construction:
Up-front bonus lease costs		3,179		—
Drilling and construction costs		442,218		344,439
Interest capitalized		39,581		14,827

		484,978		359,266

Construction-in-process	$	518,595	$	394,224

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The following tables present a rollforward of the construction-in-process for the years ended December 31, 2009, 2008 and 2007:


	Projects Under Exploration and Development
	Up-Front Bonus			Exploration and			Interest
	Lease Costs			Development Costs			Capitalized			Total
	(Dollars in thousands)

Balance at December 31, 2006	$	—		$	844		$	—		$	844
Cost incurred during the year		8,207			15,184			205			23,596

Balance at December 31, 2007		8,207			16,028			205			24,440
Cost incurred during the year		9,079			33,568			2,280			44,927
Write off of unsuccessful exploration costs		—			(9,278	)		(550	)		(9,828	)
Transfer of projects under exploration and development to projects under construction		—			(23,261	)		(1,320	)		(24,581	)

Balance at December 31, 2008 (as restated)		17,286			17,057			615			34,958
Cost incurred during the year		1,760			24,961			2,003			28,724
Write off of unsuccessful exploration costs		—			(1,505	)		(862	)		(2,367	)
Transfer of projects under exploration and development to projects under construction		(3,179	)		(22,815	)		(1,704	)		(27,698	)

Balance at December 31, 2009	$	15,867		$	17,698		$	52		$	33,617

The above table reflects a reclassification of $17,286,000 and $8,207,000 as of December 31, 2008 and 2007, respectively, of up-front bonus lease costs from property, plant and equipment to construction-in-process.


	Projects Under Construction
	Up-Front Bonus		Drilling and			Interest
	Lease Costs		Construction Costs			Capitalized			Total
	(Dollars in thousands)

Balance at December 31, 2006	$	—	$	162,676		$	5,555		$	168,231
Cost incurred during the year		—		202,933			6,631			209,564
Transfer of completed projects to property, plant and equipment		—		(152,905	)		(7,109	)		(160,014	)

Balance at December 31, 2007		—		212,704			5,077			217,781
Cost incurred during the year		—		346,298			19,032			365,330
Transfer of completed projects to property, plant and equipment		—		(237,824	)		(10,602	)		(248,426	)
Transfer from projects under exploration and development		—		23,261			1,320			24,581

Balance at December 31, 2008 (as restated)		—		344,439			14,827			359,266
Cost incurred during the year		—		191,470			25,393			216,863
Transfer of completed projects to property, plant and equipment		—		(116,506	)		(2,343	)		(118,849	)
Transfer from projects under exploration and development		3,179		22,815			1,704			27,698

Balance at December 31, 2009	$	3,179	$	442,218		$	39,581		$	484,978

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Property, plant and equipment

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


	December 31,
	2009			2008
	(Dollars in thousands)

Land where geothermal resource is located	$	25,507		$	17,914
Leasehold improvements		1,086			2,605
Machinery and equipment		65,600			53,709
Office equipment		12,200			11,345
Automobiles		4,679			3,062
Geothermal and recovered energy generation power plants, including
geothermal wells and exploration and resource development costs:
United States of America		910,793			812,020
Foreign countries		254,849			254,849
Asset retirement cost		8,474			8,815

		1,283,188			1,164,319
Less accumulated depreciation		(284,495	)		(223,684	)

Property, plant and equipment, net	$	998,693		$	940,635

The above table reflects a reclassification of $17,286,000 as of December 31, 2008, of up-front bonus lease costs, from property, plant and equipment to construction-in-process.

Depreciation expense for the years ended December 31, 2009, 2008 and 2007 amounted to $60,811,000, $51,873,000 and $45,607,000, 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 $1,287,836,000 and $1,108,570,000 (as restated) as of December 31, 2009 and 2008, respectively.

Foreign Operations

The net book value of property, plant and equipment, including construction-in-process, located outside of the United States was approximately $229,452,000 and $226,289,000 as of December 31, 2009 and 2008, 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 to the power plants was $110,810,000 and $114,136,000 as of December 31, 2009 and 2008, respectively. The Company sells the electricity produced by the power plants to Kenya Power and Lighting Co. Ltd. (“KPLC”) under a 20-year PPA.

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 $14,216,000 and $15,008,000 at December 31, 2009 and 2008, 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

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period of the PPA. The net book value of the assets related to the power plant was $30,776,000 and $34,640,000 at December 31, 2009 and 2008, 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 $48,623,000 and $39,947,000 at December 31, 2009 and 2008, respectively.

The Company, through its wholly owned subsidiary, Geothermal Development Limited (“GDL”), owned a power plant in New Zealand. The net book value of the assets related to the power plant was $11,940,000 and $9,856,000 at December 31, 2009 and 2008 respectively. The former shareholder of GDL exercised its call option to purchase from the Company its shares in GDL in January 2010 (see Note 22).


NOTE 7 —	INTANGIBLE ASSETS

Intangible assets consist mainly of all of the Company’s PPAs acquired in business combinations and amounted to $41,981,000 and $44,853,000, net of accumulated amortization of $18,907,000 and $15,710,000, as of December 31, 2009 and 2008, respectively. Amortization expense for the years ended December 31, 2009, 2008 and 2007 amounted to $3,197,000, $3,136,000, and $3,247,000, respectively.

Estimated future amortization expense for the intangible assets as of December 31, 2009 is as follows:


	(Dollars in thousands)

Year ending December 31:
2010	$	3,195
2011		3,195
2012		3,195
2013		3,195
2014		3,195
Thereafter		26,006

Total	$	41,981


NOTE 8 —	ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses consist of the following:


	December 31,
	2009		2008
	(Dollars in thousands)

Trade payables	$	46,410	$	82,624
Salaries and other payroll costs		10,441		9,529
Customer advances		6,511		3,024
Accrued interest		2,061		527
Income tax payable		2,589		1,803
Property tax		1,629		840
Other		4,352		4,989

Total	$	73,993	$	103,336

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


NOTE 9 —	LONG-TERM DEBT AND CREDIT AGREEMENTS

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


	December 31,
	2009			2008
	(Dollars in thousands)

Limited and non-recourse agreements:
Non-recourse agreement:
Senior loans (the Zunil power plant)	$	5,225		$	9,013
Loan agreement (the Olkaria III power plant)		99,474			—
Loan agreement (the Amatitlan power plant)		41,056			—
Limited recourse agreement:
Credit facility agreement		2,588			5,477

		148,343			14,490
Less current portion		(19,191	)		(6,676	)

Non-current portion	$	129,152		$	7,814

Full recourse agreements:
Loans from institutional investors:	$	40,000		$	—
Loan from a commercial bank		50,000			—

		90,000			—
Less current portion		(12,823	)		—

Non-current portion	$	77,177		$	—

Revolving credit lines with banks	$	134,000		$	100,000

Senior Secured Notes (non-recourse):
Ormat Funding Corp. (“OFC”)	$	146,323		$	155,326
OrCal Geothermal Inc. (“OrCal”)		105,776			116,819

Total		252,099			272,145
Less current portion		(20,227	)		(20,085	)

Non-current portion	$	231,872		$	252,060

Senior Loans (the Zunil Power Plant)

International Finance Corporation (“IFC”) Loan

Orzunil, a wholly owned subsidiary of the Company, has a senior loan agreement with IFC. The loan matures on November 15, 2011, and is payable in 47 quarterly installments. The loan has a fixed annual interest rate of 11.775%.

Commonwealth Development Corporation (“CDC”) Loan

Orzunil has a senior loan agreement with CDC. The loan matures on August 15, 2010, and is payable in 42 quarterly installments. The loan has a fixed annual interest rate of 10.300%.

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There are various restrictive covenants under these Senior Loans, which include limitations on Orzunil’s ability to make distributions to its shareholders. Management believes that as of December 31, 2009, Orzunil was in compliance with the covenants under the Senior Loans.

Loan Agreement (the Olkaria III Complex)

In March 2009, the Company’s wholly owned subsidiary, OrPower 4, Inc. (“OrPower 4”), entered into a project financing loan of $105.0 million to refinance its investment in the 48 MW Olkaria III complex located in Kenya (the “Olkaria Loan”). The Company initially financed the construction of Phase I and Phase II of the project, as well as the drilling of wells with corporate funds. The Olkaria Loan is 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 Olkaria Loan will mature on December 15, 2018, and is payable in 19 equal semi-annual installments, commencing December 15, 2009. Interest on the Olkaria Loan is variable based on 6-month LIBOR plus 4.0% and the Company 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 Olkaria Loan at 6.90% per annum.

There are various restrictive covenants under the Olkaria Loan, which include limitations on OrPower 4’s ability to make distributions to its shareholders. Management believes that as of December 31, 2009, OrPower 4 was in compliance with the covenants under the Olkaria Loan.

Debt service reserve

As required under the terms of the Olkaria 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 Olkaria Loan in the following six months. This restricted cash account is classified as current on the consolidated balance sheet. As of December 31, 2009, the balance of such account was $18.3 million. In addition, as of December 31, 2009, part of the restricted cash accounts was funded by a letter of credit in the amount of approximately $5.9 million.

Loan Agreement (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, to refinance its investment in the 20 MW Amatitlan geothermal power plant located in Amatitlan, Guatemala (the “Amatitlan Loan”). The Company initially financed the construction of the project, as well as the drilling of wells with corporate funds. The Amatitlan Loan is provided by TCW Global Project Fund II, Ltd. (“TCW”). The Amatitlan Loan will mature on June 15, 2016, and will be payable in 28 quarterly installments. The Amatitlan Loan bears annual interest at a rate of 9.83%.

There are various restrictive covenants under the Amatitlan Loan, which include limitations on Ortitlan’s ability to make distributions to its shareholders. Management believes that as of December 31, 2009, Ortitlan was in compliance with the covenants under the Amatitlan Loan.

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. This restricted cash account is classified as current on the consolidated balance sheet. As of December 31, 2009, the balance of such account was $4.5 million.

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Credit Facility Agreement (the Momotombo Power Plant)

Ormat Momotombo Power Company (“OMPC”), a wholly owned subsidiary of the Company, entered into a credit facility agreement with Bank Hapoalim B.M. Principal and interest payments on the Phase I Loan are payable in 32 equal quarterly payments that commenced upon completion of Phase I of the power plant in December 2001. Interest on the Phase I Loan is variable based on 3-month LIBOR plus 2.375%. Principal and interest payments on the Phase II Loan are payable in 28 equal quarterly payments that commenced in March 2004. Interest on the Phase II Loan is variable based on 3-month LIBOR plus 3.0%, and is added to the outstanding balances of the Phase II Loan until the commencement of the principal and interest payments. At December 31, 2009 and 2008, $893,000 and $2,086,000, respectively, was outstanding under the Phase I Loan, and $1,695,000 and $3,391,000, respectively, was outstanding under the Phase II Loan. The Credit Facility Agreement is collateralized by liens over all real and personal property comprising the Momotombo power plant and the Company’s ownership interest in OMPC. There are various restrictive covenants under the Credit Facility Agreement, which include maintaining certain levels of debt to equity ratio and debt service coverage ratio, and limitations on additional indebtedness and payment of dividends.

Management believes that OMPC was in compliance with the covenants under the Credit Facility Agreement as of December 31, 2009.

Loan agreements with 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 commencing January 16, 2010, and bears an annual interest at a rate 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 commencing February 1, 2012, and bears interest at 6-month LIBOR plus 5.0%.

There are various restrictive covenants under the above loans, which include among others maintaining a certain minimum debt coverage ratio. Management believes that as of December 31, 2009, the Company was in compliance with the covenants.

Loan agreements with 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 commencing May 10, 2010, and bears interest at 6-month LIBOR plus 3.25%.

There are various restrictive covenants under the above loan, which include among others maintaining a certain minimum debt coverage ratio. Management believes that as of December 31, 2009, the Company was in compliance with the covenants.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Future minimum payments

Future minimum payments under long-term obligations, excluding the senior secured notes and notes payable to Parent, as of December 31, 2009 are as follows:


	(Dollars in thousands)

Year ending December 31:
2010	$	32,014
2011		28,032
2012		30,090
2013		30,567
2014		31,087
Thereafter		86,553

Total	$	238,343

Revolving credit lines with commercial banks

As of December 31, 2009, the Company has credit agreements with six commercial banks in the aggregate amount of $325.0 million. Under these credit agreements, the Company, or its Israeli subsidiary can request extensions of credit in the form of loans and/or the issuance of one or more letters of credit. Five credit agreements totaling $310.0 million have an original term of three years and one credit agreement totaling $15.0 million, has an original term of two years.

Loans and draws under the credit agreements or under any letters of credit bear interest at the respective bank’s cost of funds plus a margin. The Company’s, or its Israeli subsidiary’s, obligations under the credit agreements are unsecured, but both entities are subject to a negative pledge in favor of the banks and certain other customary restrictive covenants. Some of the loan agreements contain cross-default provisions with respect to other material indebtedness owed by the Company to any third party.

As of December 31, 2009, loans in the amount of $134.0 million were outstanding under such credit agreements. The loans are for a period of three months or less and the Company intends to replace them with new draw-downs from the same or other lines of credit. The loans bear interest at an annual weighted average rate of 1.7% as of December 31, 2009 and are due in 2011.

Restrictive covenants

Under these agreements and the letter of credit agreements (see Note 20), the Company and its Israeli subsidiary, Ormat Systems, have agreed to certain negative covenants, including, but not limited to, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over the Company’s 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 the Company’s assets. In some cases, the Company and Ormat Systems have agreed to maintain certain financial ratios such as a debt service coverage ratio and a debt to equity ratio. The Company does not expect that these covenants or ratios, which apply to the Company on a consolidated basis, will materially limit its ability to execute its future business plans or operations. 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. Management believes that as of December 31, 2009, the Company was in compliance with the covenants under the credit agreements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

OFC Senior Secured Notes

On February 13, 2004, Ormat Funding Corp. (“OFC”), a wholly owned subsidiary, issued $190.0 million, 8 1 / 4 % Senior Secured Notes (“OFC Senior Secured Notes”) in an offering subject to Rule 144A and Regulation S of the Securities Act of 1933, as amended, 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 that commenced on June 30, 2004. 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 and payment of dividends.

In November 2008, the Company acquired from an OFC noteholder a portion of the OFC Senior Secured Notes with an outstanding principal amount of approximately $1.7 million and recognized an immaterial gain.

Management believes that as of December 31, 2009, OFC was in compliance with the covenants contained in the indenture governing the OFC Senior Secured Notes.

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 on the consolidated balance sheet. As of December 31, 2009 and 2008, the balance of such account was $0.1 million and $3.7 million, respectively. In addition, as of December 31, 2009 and 2008, part of the restricted cash accounts was funded by a letter of credit in the amount of approximately $11.1 million and $10.6 million, respectively (see Note 20).

Future minimum payments under the OFC Senior Secured Notes, as of December 31, 2009, are as follows:


	(Dollars in thousands)

Year ending December 31:
2010	$	10,011
2011		11,290
2012		10,886
2013		11,817
2014		13,703
Thereafter		88,616

Total	$	146,323

OrCal Senior Secured Notes

On December 8, 2005, OrCal Geothermal Inc. (“OrCal”), a wholly owned subsidiary, issued $165.0 million, 6.21% Senior Secured Notes (“OrCal Senior Secured Notes”) in an offering subject to Rule 144A and Regulation S

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of the Securities Act of 1933, as amended, and received net cash proceeds of approximately $161.1 million, after deduction of issuance costs of approximately $3.9 million, which have been included in deferred financing costs in the consolidated balance sheet. The OrCal Senior Secured Notes have been rated BBB- by Fitch. 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 which commenced on June 30, 2006. 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 and payment of dividends. Management believes that as of December 31, 2009, OrCal was in compliance with the covenants under the OrCal Senior Secured Notes.

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 on the consolidated balance sheet. As of December 31, 2009 and 2008, the balance of such account was $2.6 million and $7.5 million, respectively. In addition, as of December 31, 2009 and 2008, part of the restricted cash accounts was funded by a letter of credit in the amount of $11.3 million for both years (see Note 20).

Future minimum payments under the OrCal Senior Secured Notes, as of December 31, 2009 are as follows:


	(Dollars in thousands)

Year ending December 31:
2010	$	10,216
2011		9,700
2012		9,312
2013		10,391
2014		11,107
Thereafter		55,050

Total	$	105,776

Credit agreement with Union Bank

On February 15, 2006, a subsidiary of the Company entered into a $25.0 million credit agreement with Union Bank, N.A. (“Union Bank”). In December 2008, the subsidiary entered into an amendment to the credit agreement. Under the amendment, the credit termination date was extended to February 15, 2012 and the aggregate amount available under the credit agreement was increased to $37.5 million. Under the credit agreement, as amended, the Company can request extensions of credit in the form of loans and/or the issuance of one or more 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 has entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which the Company agreed to guarantee the subsidiary’s obligations

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under the credit agreement. The subsidiary’s obligations under the credit agreement are otherwise unsecured by any of its (or any of its subsidiaries’) assets. There are various restrictive covenants under the credit agreement, which include maintaining certain levels of tangible net worth, leverage ratio, minimum coverage ratio, and a distribution coverage ratio. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios. Management believes that as of December 31, 2009, the Company was in compliance with the covenants under the credit agreement. As of December 31, 2009, twelve letters of credit with an aggregated stated amount of $35.4 million were issued and outstanding under the credit agreement.


NOTE 10 —	PUNA POWER PLANT LEASE TRANSACTIONS

The Company’s wholly owned subsidiary in Hawaii, Puna Geothermal Ventures (“PGV”) entered into transactions involving the Puna geothermal power plant located on the Big Island of Hawaii (the “Puna Power Plant”).

Pursuant to a 31-year head lease (the “Head Lease”), PGV leased its geothermal 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, 2009 and 2008 amounted to $47.8 million and $50.5 million, net of accumulated depreciation of $14.6 million and $11.9 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, 2009, are as follows:


	(Dollars in thousands)

Year ending December 31:
2010	$	7,567
2011		8,061
2012		8,199
2013		8,062
2014		8,647
Thereafter		47,218

Total	$	87,754

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 $11.7 million and $9.2 million as of December 31, 2009 and 2008, respectively, and were included in restricted cash accounts in the consolidated balance sheets. As of December 31, 2009 and 2008, $2.5 million and $3.0 million, respectively, of such accounts were classified as non-current, since they are invested in auction rate securities which experienced multiple failed auctions due to a lack of liquidity in the market for these securities, as explained in Note 5, and the

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remaining $9.2 million and $6.2 million, respectively, were classified as current as they are used for current payments.

Distribution account

PGV maintains an account to deposit its remaining cash, after making all of the necessary payments and transfers as provided for in the lease agreements, in order to make distributions to Ormat Nevada Inc. (“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, 2009 and 2008, the balance of such account was $0.7 million and $0.6 million, respectively. This amount can be distributed to Ormat Nevada Inc. currently and has been classified as current restricted assets.


NOTE 11 —	OPC TRANSACTION

In June 2007, a wholly owned subsidiary of the Company, Ormat Nevada, entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. ( Morgan Stanley Geothermal LLC and Lehman-OPC LLC), under which those investors purchased, for cash, interests in a newly formed subsidiary of Ormat Nevada, OPC LLC (“OPC”), entitling the investors to certain tax benefits (such as production tax credits 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 and will receive initially all of the distributable cash flow generated by the power plants until it recovers the capital that it has invested in the power plants, while the investors will receive substantially all of the production tax credits and the taxable income or loss (together, the “Economic Benefits”), and the distributable cash flow after Ormat Nevada has recovered its capital. 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 “Flip Date”), Ormat Nevada will receive 95% of both distributable cash and taxable income on a going forward basis. Following the 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 Flip Date. The actual Flip Date is not known with certainty and is determined by the operating results of OPC. This residual 5% interest represents a noncontrolling interest which 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. Ormat Nevada is currently allocated the cash earnings in OPC and therefore, the amount allocated to the 5% residual interest represents the noncash loss of OPC which principally represents depreciation on the property, plant and equipment. As a result of Ormat Nevada’s acquisition, of all of the Class B membership units of OPC held by Lehman-OPC LLC (see below), the residual interest decreased to 3.5% on October 30, 2009.

The Company’s voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. The Company owns, through its subsidiary, Ormat Nevada, all of the Class A membership units, which represent 75% of the voting rights in OPC and 30% of the Class B membership units, which represent 7.5% of the voting rights of OPC, and in total the Company has 82.5% of the voting rights in OPC. The investors own 70% of the Class B membership units, which represent 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

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membership units. Following the Flip Date, Ormat Nevada’s voting rights will increase to 96.5% and the investor’s voting rights will decrease to 3.5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the Flip Date and therefore has continued to consolidate OPC.

On October 30, 2009, Ormat Nevada acquired Lehman-OPC LLC’s 30% interest in the Class B membership units of OPC. The membership units were acquired from Lehman-OPC LLC 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. As a result, the repurchase of these interests at a discount resulted in a pre-tax gain of $13.3 million in the fourth quarter of 2009. In addition, an amount of approximately $1.1 million has been classified from noncontrolling interest to additional paid-in capital representing the 1.5% residual interest of Lehman-OPC LLC’s Class B membership units. As a result of that transaction, Lehman-OPC LLC retains no further interest in OPC.

The Company adopted the new accounting guidance for noncontrolling interests in a subsidiary on January 1, 2009. Under this guidance, noncontrolling interests are to be presented on the balance sheet as a component of equity. The adoption of this standard resulted in retrospective presentation and disclosure changes to the consolidated balance sheet as of December 31, 2008 and the consolidated statements of operations and comprehensive income for the years ended December 31, 2008 and 2007. These changes are denoted in the table below:

Consolidated balance sheet data as of December 31, 2008:


	Balance as of					Revised and Restated
	December 31, 2008,		Application of New			Balance As of
	As Restated		Accounting Standard			December 31, 2008
	(Dollars in thousands)

Deferred financing and lease costs, net	$	16,127	$	3,113	⁽¹⁾	$	19,240

Total assets	$	1,627,863	$	3,113		$	1,630,976

Liability associated with sale of equity interests	$	—	$	113,327	⁽²⁾	$	113,327

Total liabilities		670,414		113,327			783,741

Minority interest		117,245		(117,245	)		—

Equity:
The Company’s stockholders’ equity:
Common stock		45		—			45
Additional paid-in capital		701,273		—			701,273
Retained earnings		138,241		—			138,241
Accumulated other comprehensive income		645		—			645

		840,204		—			840,204
Noncontrolling interest		—		7,031	⁽³⁾		7,031

Total equity		840,204		7,031			847,235

Total liabilities and equity	$	1,627,863	$	3,113		$	1,630,976


⁽¹⁾		Represents transaction costs that had previously been reflected as a component of minority interest on the consolidated balance sheets. Such costs are amortized using the effective interest method until the Flip Date.

⁽²⁾		Represents unamortized liability associated with sale of equity interests in OPC.

⁽³⁾		Represents noncontrolling interest in OPC.

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Consolidated statements of operations and comprehensive income data for the year ended December 31, 2008:


							Revised Year
	Year Ended						Ended
	December 31,			Application of New			December 31,
	2008 (As Restated)			Accounting Standard			2008
	(Dollars in thousands)

Other income (expense):
Interest income	$	3,118		$	—		$	3,118
Interest expense, net		(7,677	)		(7,268	) ⁽¹⁾		(14,945	)
Foreign currency translation and transaction losses		(7,721	)		—			(7,721	)
Income attributable to sale of tax benefits		—			18,118	⁽²⁾		18,118
Other non-operating expense, net		(3,424	)					(3,424	)

Income before income taxes and equity in income of investees		35,075			10,850			45,925
Income tax provision		(4,358	)		—			(4,358	)
Minority interest		11,166			(11,166	)		—
Equity in income of investees, net		1,725			—			1,725

Net income		43,608			(316	)		43,292
Net loss attributable to noncontrolling interest		—			316	⁽³⁾		316

Net income attributable to the Company’s stockholders	$	43,608		$	—		$	43,608

Comprehensive income:
Net income	$	43,608		$	(316	)	$	43,292
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment		(885	)		—			(885	)
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge		(293	)		—			(293	)
Change in unrealized gains or losses on marketable securities available-for-sale		435			—			435

Comprehensive income		42,865			(316	)		42,549
Comprehensive loss attributable to noncontrolling interest		—			316	⁽³⁾		316

Comprehensive income attributable to the Company’s stockholders	$	42,865		$	—		$	42,865


⁽¹⁾		Represents interest expense using the Class B members’ targeted yield on the balance of the amount paid by them and amortization of transaction costs using the effective interest method.

⁽²⁾		Represents the value of production tax credits and taxable income or loss generated by OPC allocated to the Class B members in accordance with the OPC agreements.

⁽³⁾		Represents allocation of net loss on the 5% residual to the Class B members.

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Consolidated statements of operations and comprehensive income data for the year ended December 31, 2007:


							Revised Year
	Year Ended						Ended
	December 31,			Application of New			December 31,
	2007			Accounting Standard			2007
	(Dollars in thousands)

Other income (expense):
Interest income	$	6,565		$	—		$	6,565
Interest expense, net		(26,983	)		(2,762	) ⁽¹⁾		(29,745	)
Foreign currency translation and transaction losses		(1,339	)		—			(1,339	)
Income attributable to sale of tax benefits		—			6,488	⁽²⁾		6,488
Other non-operating expense, net		(1,130	)					(1,130	)

Income before income taxes and equity in income of investees		20,574			3,726			24,300
Income tax provision		(1,822	)		—			(1,822	)
Minority interest		3,882			(3,882	)		—
Equity in income of investees, net		4,742			—			4,742

Net income		27,376			(156	)		27,220
Net loss attributable to noncontrolling interest		—			156	⁽³⁾		156

Net income attributable to the Company’s stockholders	$	27,376		$	—		$	27,376

Comprehensive income:
Net income	$	27,376		$	(156	)	$	27,220
Other comprehensive income (loss), net of related taxes:
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge		(326	)		—			(326	)
Change in unrealized gains or losses on marketable securities available-for-sale		(590	)		—			(590	)

Comprehensive income		26,460			(156	)		26,304
Comprehensive loss attributable to noncontrolling interest		—			156	⁽³⁾		156

Comprehensive income attributable to the Company’s stockholders	$	26,460		$	—		$	26,460


⁽¹⁾		Represents interest expense using the Class B members’ targeted yield on the balance of the amount paid by them and amortization of transaction costs using the effective interest method.

⁽²⁾		Represents the value of production tax credits and taxable income or loss generated by OPC allocated to the Class B members in accordance with the OPC agreements.

⁽³⁾		Represents allocation of net loss on the 5% residual to the Class B members.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


NOTE 12 —	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:


	December 31,
	2009			2008
	(Dollars in thousands)

Balance at beginning of year	$	13,438		$	13,014
Changes in price estimates		(686	)		—
Changes in estimated useful lives		—			(2,419	)
Liabilities incurred		426			1,774
Accretion expense		1,060			1,069

Balance at end of year	$	14,238		$	13,438

During the year ended December 31, 2009, the Company decreased the aggregate carrying amount of its asset retirement obligation by $686,000 due to decreased costs associated with demolition and abandonment of our property, plant and equipment. During the year ended December 31, 2008, the Company decreased the aggregate carrying amount of its asset retirement obligation by $2,419,000 due to decreased costs associated with a change in estimated settlement dates of certain of the Company’s power plants.


NOTE 13 —	STOCK-BASED COMPENSATION

Effective January 1, 2006, the Company adopted the provisions of share-based payments guidance, using the modified prospective method. In its adoption, the Company applied the provisions which allowed the use of the simplified method in developing an estimate of the expected term of “plain vanilla” share options. In December 2007, the SEC issued an extension which continues to allow, under certain circumstances, entities to use the simplified method. The Company has continued to use the simplified method to estimate the expected term of its stock-based awards.

As required by the guidance, the Company made an estimate of expected forfeitures and is recognizing compensation costs only for those stock-based awards expected to vest. As of December 31, 2009, the total future compensation cost related to unvested stock-based awards that are expected to vest is $8,323,000 which amount will be recognized over a weighted average period of 1.3 years.

During the years ended December 31, 2009, 2008 and 2007, the Company recorded compensation related to stock-based awards as follows:


	Year Ended December 31,
	2009		2008		2007
	(Dollars in thousands,
	except per share data)

Cost of revenues	$	3,296	$	2,471	$	1,769
Selling and marketing expenses		708		221		657
General and administrative expenses		1,751		1,752		1,337

Total stock-based compensation expense		5,755		4,444		3,763
Tax effect on stock-basedcompensation expense		701		483		502

Net effect of stock-based compensation expense	$	5,054	$	3,961	$	3,261

Effect of stock-based compensation expense on earnings per share	$	0.11	$	0.09	$	0.08

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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 0.38% yearly weighted average dividend rate in the year ended December 31, 2009. 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 option 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,
	2009			2008			2007

For stock-based awards issued by the Company:
Risk-free interest rates		1.6	%		2.7	%		4.5	%
Expected lives (in years)		5.1			5.0			5.0
Dividend yield		0.38	%		0.37	%		0.52	%
Expected volatility		48.6	%		38.5	%		35.7	%
Forfeiture rate		13.0	%		13.0	%		5.0	%

Stock-based awards

The 2004 Incentive Compensation Plan

On October 21, 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes the status of the 2004 Incentive Plan as of and for the years presented below (shares in thousands):


	Year Ended December 31,
	2009					2008					2007
				Weighted					Weighted					Weighted
				Average					Average					Average
				Exercise					Exercise					Exercise
	Shares			Price		Shares			Price		Shares			Price

Outstanding at beginning of year		1,233		$	39.14		817		$	35.38		539		$	27.03
Granted, at fair value:
Stock options		30			38.50		481			44.53		435			42.78
SAR’s*		573			26.84
Exercised		(79	)		15.96		(29	)		11.36		(47	)		15.81
Forfeited		(12	)		44.20		(36	)		40.01		(110	)		32.09

Outstanding at end of year		1,745			36.08		1,233			39.14		817			35.38

Exercisable at end of year		331			35.23		230			27.61		82			22.42

Weighted-average fair value of options granted during the year				$	11.63				$	16.48				$	15.88


*		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, 2009, 1,830,449 shares of the Company’s common stock are available for future grants.

The following table summarizes information about stock-based awards outstanding at December 31, 2009 (shares in thousands):


		Stock-Based Awards Outstanding						Stock-Based Awards Exercisable
				Weighted						Weighted
				Average						Average
				Remaining						Remaining
		Number of		Contractual				Number of		Contractual
Exercise		Shares		Life in		Aggregate		Shares		Life in		Aggregate
Price		Outstanding		Years		Intrinsic Value		Exercisable		Years		Intrinsic Value
						(In thousands)						(In thousands)

$	15.00		34		4.8	$	787		34		4.8	$	787
	20.10		8		4.8		133		8		4.8		133
	25.74		30		5.8		363		30		5.8		363
	26.84		572		6.2		6,294		—		—		—
	34.13		232		6.3		860		111		6.3		413
	37.90		23		3.8		—		23		3.8		—
	38.50		30		6.8		—		—		—		—
	38.85		8		4.2		—		8		4.2		—
	42.08		350		4.3		—		87		4.3		—
	45.78		428		5.3		—		—		—		—
	52.98		30		4.8		—		30		4.8		—

			1,745		5.5	$	8,437		331		5.2	$	1,696

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The following table summarizes information about stock-based awards outstanding at December 31, 2008 (shares in thousands):


		Stock-Based Awards Outstanding						Stock-Based Awards Exercisable
				Weighted						Weighted
				Average						Average
				Remaining						Remaining
		Number of		Contractual				Number of		Contractual
Exercise		Shares		Life in		Aggregate		Shares		Life in		Aggregate
Price		Outstanding		Years		Intrinsic Value		Exercisable		Years		Intrinsic Value
						(In thousands)						(In thousands)

$	15.00		105		5.8	$	1,771		105		5.8	$	1,771
	20.10		13		5.8		153		13		5.8		153
	25.74		30		6.8		184		—		—		—
	34.13		234		7.3		—		51		7.3		—
	37.90		23		4.8		—		23		4.8		—
	38.85		8		5.2		—		8		5.2		—
	42.08		350		5.3		—		—		—		—
	45.78		440		6.3		—		—		—		—
	52.98		30		5.8		—		30		5.8		—

			1,233		6.1	$	2,108		230		6.0	$	1,924

The aggregate intrinsic value in the above tables represents the total pretax intrinsic value, based on the Company’s stock price of $37.84 and $31.87 as of December 31, 2009 and 2008, 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 award exercisable as of December 31, 2009 and 2008 was 183,396 and 117,243, respectively.

The total pretax intrinsic value of stock-based award exercised during the years ended December 31, 2009, 2008, and 2007 was $1,835,000, $597,000, and $1,395,000, respectively, based on the Company’s average stock price of $35.98, $42.01 and $45.49 during the years ended December 31, 2009, 2008 and 2007, respectively.

The Parent’s Stock Option Plans

The Parent had four stock option plans. Under the Parent’s stock option plans, employees of the Company were granted options in the Parent’s ordinary shares, which are registered and traded on the Tel-Aviv Stock Exchange. None of the options were exercisable or convertible into shares of the Company.

As of December 31, 2009, all the options under the parent stock options plans have been fully exercised or expired, and no shares of the Parent’s ordinary shares are available for future grants.

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The following table summarizes the status of the Parent’s Plans as of and for the periods presented below (shares in thousands):


	Year Ended December 31,
	2009					2008					2007
				Weighted					Weighted					Weighted
				Average					Average					Average
				Exercise					Exercise					Exercise
	Shares			Price		Shares			Price		Shares			Price

Outstanding at beginning of year		284		$	3.78		403		$	3.68		—		$	—
Exercised		(284	)		3.78		(97	)		3.78		(657	)		2.05
Expired		—			—		(1	)		1.75		—			—
Forfeited		—			—		(21	)		1.97		(38	)		3.68

Outstanding at end of year		—			—		284			3.78		403			3.68

Options exercisable at end of year		—			—		284		$	3.78		128		$	3.47

The following table summarizes information about stock options outstanding at December 31, 2008 (shares in thousands):

Options Outstanding

Options Exercisable

Weighted

Average

Number of

Remaining

Number of

Remaining

Exercise

Shares

Contractual

Aggregate

Shares

Contractual

Aggregate

Price

Outstanding

Life in Years

Intrinsic Value

Exercisable

Life in Years

Intrinsic Value

(In thousands)

$3.78

284

0.3

673

284

0.3

673

The aggregate intrinsic value in the above table represents the total pre-tax intrinsic value, based on the Parent’s stock price of $6.15 as of December 31, 2008, which would have potentially been received by the option holders had all option holders exercised their options as of those dates. The total number of in-the-money options exercisable as of December 31, 2008 was 283,942.

The total pretax intrinsic value of options exercised during the years ended December 31, 2009, 2008, and 2007 was $1,163,000, $1,130,985 and $7,217,000 based on the Parent’s average stock price of $7.88, $13.19, and $13.03 during the year ended December 31, 2009, 2008, and 2007, respectively.


NOTE 14 —	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, Guatemala, and New Zealand. 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 2030. Generally, capacity payments are payments calculated based on the amount of time that the power plants are available to generate electricity. The energy payments are payments calculated based on the amount of electrical energy delivered at a designated delivery point. The price terms are customary in the industry and include, among others, a fixed price, short-run avoided cost (“SRAC”) (the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others), and a fixed price with an escalation clause that includes the value for environmental attributes, known as renewable energy credits. Certain of the PPAs provide for bonus payments in the event that the Company is able to exceed certain target levels and potential payments by the Company if it fails to meet minimum target levels. One PPA gives the power purchaser or its designee the right of first refusal to acquire the geothermal power plants at fair market value. Upon satisfaction of certain conditions specified in this PPA and subject to receipt of requisite approvals and negotiations between the parties, the Company has the right to demand that the power

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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. 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 concluded that all such PPAs contained a lease element requiring lease accounting. Future minimum lease revenues under PPAs which contain a lease element as of December 31, 2009 were as follows:


	(Dollars in thousands)

Year ending December 31:
2010	$	185,559
2011		184,299
2012		181,504
2013		184,081
2014		186,149
Thereafter		2,111,587

Total	$	3,033,179


NOTE 15 —	INTEREST EXPENSE, NET

The components of interest expense are as follows:


	Year Ended December 31,
	2009			2008			2007
	(Dollars in thousands)

Parent	$	1,121		$	3,598		$	5,941
Interest related to sale of tax benefits		7,568			7,268			2,762
Other		34,947			25,391			27,877
Less — amount capitalized		(27,395	)		(21,312	)		(6,835	)

	$	16,241		$	14,945		$	29,745


NOTE 16 —	INCOME TAXES

Income before provision for income taxes and equity in income of investees consisted of:


	Year Ended December 31,
	2009		2008 (As Restated)		2007
	(Dollars in thousands)

U.S	$	38,371	$	35,822	$	19,197
Non-U.S. (foreign)		44,970		10,103		5,103

	$	83,341	$	45,925	$	24,300

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The components of income tax expense (income) are as follows:


	Year Ended December 31,
	2009		2008 (As Restated)			2007
	(Dollars in thousands)

Current:
State	$	885	$	(662	)	$	—
Foreign		12,082		1,779			6,752

	$	12,967	$	1,117		$	6,752

Deferred:
Federal		2,114		3,063			(786	)
State		1,359		1,295			168
Foreign		484		(1,117	)		(4,312	)

		3,957		3,241			(4,930	)

	$	16,924	$	4,358		$	1,822

The significant components of the deferred income tax expense (benefit) are as follows:


	Year Ended December 31,
	2009			2008 (As Restated)			2007
	(Dollars in thousands)

Deferred tax expense (exclusive of the effect of other components listed below)	$	(4,588	)	$	5,062		$	18,369
Benefit of operating loss carry forwards — U.S.		(23,036	)		4,278			(14,054	)
Change in foreign income tax		9,134			402			(4,312	)
Change in lease transaction		3,919			(943	)		(1,518	)
Change in tax monetization transaction		7,858			4,947			4,597
Change in intangible drilling costs		21,659			—			—
Benefit of production tax credits		(10,989	)		(10,505	)		(8,012	)

	$	3,957		$	3,241		$	(4,930	)

The difference between the U.S. federal statutory tax rate and the Company’s effective tax rate are as follows:


	Year Ended December 31,
	2009			2008 (As Restated)			2007

U.S. federal statutory tax rate		35.0	%		35.0	%		35.0	%
State income tax, net of federal benefit		2.6			1.4			0.7
Effect of foreign income tax, net		(3.8	)		(6.3	)		(1.5	)
Production tax credits		(13.2	)		(22.9	)		(32.9	)
Withholding tax		—			—			4.2
Other, net		(0.3	)		2.3			2.0

Effective tax rate		20.3	%		9.5	%		7.5	%

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The net deferred tax assets and liabilities consist of the following:


	December 31,
	2009			2008 (As Restated)
	(Dollars in thousands)

Deferred tax assets (liabilities):
Net foreign deferred taxes, primarily depreciation	$	(21,225	)	$	(12,091	)
Depreciation		(74,961	)		(71,913	)
Intangible drilling costs		(21,659	)		—
Net operating loss carry forward — U.S.		49,996			26,960
Intercompany profit elimination		31,724			22,940
Tax monetization transaction		(17,402	)		(9,544	)
Lease transaction		6,378			10,297
Investment tax credits		1,971			1,971
Production tax credits		34,212			23,223
Stock options amortization		1,375			1,304
Unconsolidated investment		(5,949	)		(4,586	)
Accrued liabilities and other		(2,841	)		(1,220	)

Total	$	(18,381	)	$	(12,659	)

Deferred taxes are included in the consolidated balance sheets as follows:


	December 31,
	2009			2008 (As Restated)
	(Dollars in thousands)

Current assets	$	3,617		$	3,003
Non-current assets		22,532			13,965
Non-current liabilities		(44,530	)		(29,627	)

	$	(18,381	)	$	(12,659	)

As disclosed in Note 11, the Company adopted the new accounting guidance for noncontrolling interests in a subsidiary on January 1, 2009. The adoption of this standard resulted in retrospective presentation changes to the consolidated balance sheet as of December 31, 2008 and the consolidated statements of operations and comprehensive income for the years ended December 31, 2008 and 2007. While the adoption changed the amounts reported in “Income before income taxes and equity in income of investees”, the adoption had no effect on the total income tax provision reported in the consolidated statements of operations and comprehensive income or on deferred income tax assets or liabilities reported on the consolidated balance sheet.

Realization of the deferred tax assets and tax credits is dependent on generating sufficient taxable income prior to expiration of the net operating loss (“NOL”) carryforwards and tax credits. Although realization is not assured, management believes it is more likely than not that the deferred tax assets at December 31, 2009 will be realized.

At December 31, 2009, the Company had U.S. federal NOL carryforwards of approximately $139.8 million and state NOL carryforwards of approximately $22.6 million, available to reduce future taxable income, which expire between 2021 and 2029 for federal NOLs and between 2014 and 2019 for state NOLs. The investment tax credits in the amount of $2.0 million at December 31, 2009 are available for a 20-year period and expire in 2022 and 2023. The production tax credits in the amount of $34.2 million at December 31, 2009 are available for a 20-year period and expire between 2026 and 2029.

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The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $157.8 million at December 31, 2009. 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.

Uncertain tax positions

The Company adopted the accounting guidance for uncertain tax positions, on January 1, 2007. As a result of the adoption, the Company recognized, as a cumulative effect of change in accounting principle, a $0.3 million increase in the liability for unrecognized tax benefits and a corresponding decrease in beginning retained earnings. This amount consists of interest and penalties related to uncertain tax positions. In addition, on January 1, 2007, the Company reclassified its liability for uncertain tax positions in the amount of $3.4 million from long-term deferred income tax liabilities to liability for unrecognized tax benefits. The liability for unrecognized tax benefits of $4.9 million and $3.4 million at December 31, 2009 and 2008, 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,
	2009			2008			2007
	(Dollars in thousands)

Balance at beginning of year	$	3,425		$	5,330		$	3,754
Additions based on tax positions taken
in prior years		964			929			156
Additions based on tax positions taken
in the current year		1,282			814			1,420
Decrease for settlements with taxing authorities		(740	)		(3,648	)		—

Balance at end of year	$	4,931		$	3,425		$	5,330

The Company and its U.S. subsidiaries file consolidated income tax returns for federal and state purposes. As of December 31, 2009, 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 2000-2009 and by local state jurisdictions for the years 2002-2009.

The Company’s foreign subsidiaries remain open to examination by the local income tax authorities in the following countries for the years indicated:


Israel		2007 — 2009
Nicaragua		2006 — 2009
Kenya		2006 — 2009
Guatemala		2005 — 2009
Philippines		2006 — 2009
New Zealand		2007 — 2009

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

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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 recently enacted American Recovery and Reinvestment Act. The Company is permitted to claim 30% of the cost of each new geothermal power plant in the United States as an investment tax credit against its federal income taxes. Alternatively, the Company is permitted to claim a production tax credit, which in 2009 was 2.1 cents per kWh and which is adjusted annually for inflation. The production tax credit 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 production tax credit and the 30% investment tax credit 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 production tax credit or the investment tax credit, 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 investment tax credit, the Company’s “tax base” in the plant that it can recover through depreciation must be reduced by half of the tax credit. If the Company claims the production tax credit, there is no reduction in the tax basis for depreciation. Companies that begin construction, or place qualifying renewable energy facilities in service, during 2009 or 2010 may choose to apply for a cash grant from the U.S. Department of Treasury in an amount equal to the investment tax credit. Under the American Recover and Reinvestment Act, the U.S. Department of 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.

On June 7, 2007 and April 17, 2008, a wholly-owned subsidiary, Ormat Nevada, concluded transactions to monetize production tax credits and other favorable tax attributes (see Note 11).

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, 2009, 2008, and 2007 is $3.8 million, $3.9 million and, $2.0 million, respectively ($0.08, $0.09 and, $0.05 per share of common stock, respectively).

Israel — The Company’s operations in Israel through its wholly owned Israeli subsidiary, Ormat Systems Ltd. (“Ormat Systems”), are taxed at the regular corporate tax rate of 29% in 2007, 27% in 2008, 26% in 2009, 25% in 2010, 24% in 2011, 23% in 2012, 22% in 2013, 21% in 2014, 20% in 2015, and 18% in 2016 and thereafter. Ormat Systems is entitled to “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 is subject to reduced Israeli income tax rates which will not exceed 25% for an additional five years. Ormat Systems is 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 will be subject to reduced Israeli income tax rates which will not exceed 25% for an additional five years. These benefits are subject to certain conditions, including among other things, that all transactions between Ormat Systems and its affiliates are at arms 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 Israeli Tax Authorities in order to maintain the tax benefits. In addition, as an industrial company, Ormat Systems is entitled to accelerated depreciation on equipment used for its industrial activities. Under the

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provisions of certain tax regulations published in Israel in 2005, industrial companies whose operations are mostly “Eligible Operations” are entitled to claim accelerated depreciation at the rate of 100% on machinery and equipment acquired from July 1, 2005 to December 31, 2006. Accelerated depreciation is to be claimed over two years. In the year in which the equipment was acquired, the regular depreciation rate is to be claimed with the remainder to be claimed in the second year. Under the provisions of certain tax regulations published in Israel in July 2008, industrial companies whose operations are mostly “Eligible Operations” are entitled to claim accelerated depreciation at the rate of 50% on machinery and equipment acquired from June 1, 2008 to May 31, 2009 and placed in service at the later of six months after acquisition or before May 31, 2009.

Other significant foreign countries — The Company’s operations in Nicaragua, Kenya, and New Zealand are taxed at the rates of 25%, 37.5%, and 33%, respectively.


NOTE 17 —	BUSINESS SEGMENTS

The Company has two reporting segments: Electricity and Product Segments. Such segments are managed and reported separately as each offers different products and serves different markets. The Electricity Segment is engaged in the sale of electricity from the Company’s power plants pursuant to PPAs. The Product Segment is engaged in the manufacture, including design and development, of turbines and power units for the supply of electrical energy and in the associated construction of power plants utilizing the power units manufactured by the Company to supply energy from geothermal fields and other alternative energy sources. Transfer prices between the operating segments were determined on current market values or cost plus markup of the seller’s business segment.

Summarized financial information concerning the Company’s reportable segments is shown in the following tables:


	Electricity		Product			Consolidated
	(Dollars in thousands)

Year Ended December 31, 2009
Net revenues from external customers	$	255,855	$	159,389		$	415,244
Intersegment revenues		—		33,751			33,751
Depreciation and amortization expense		62,283		2,093			64,376
Operating income		47,312		21,461			68,773
Segment assets at year end*		1,757,327		97,674			1,855,001
Expenditures for long-lived assets		265,252		5,371			270,623
Year Ended December 31, 2008 (As Restated)
Net revenues from external customers	$	252,256	$	92,577		$	344,833
Intersegment revenues		—		81,557			81,557
Depreciation and amortization expense		58,560		1,568			60,128
Operating income		45,081		5,698			50,779
Segment assets at year end*		1,555,315		75,661			1,630,976
Expenditures for long-lived assets		412,734		3,872			416,606
Year Ended December 31, 2007
Net revenues from external customers	$	215,969	$	79,950		$	295,919
Intersegment revenues		—		109,895			109,895
Depreciation and amortization expense		49,398		1,084			50,482
Operating income		43,689		(228	)		43,461
Segment assets at year end*		1,230,220		47,148			1,277,368
Expenditures for long-lived assets		214,221		2,137			216,358


*		Segment assets of the Electricity Segment include unconsolidated investments.

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Reconciling information between reportable segments and the Company’s consolidated totals is shown in the following table:


	Year Ended December 31,
	2009			2008 (As Restated)			2007
	(Dollars in thousands)

Revenues:
Total segment revenues	$	415,244		$	344,833		$	295,919
Intersegment revenues		33,751			81,557			109,895
Elimination of intersegment revenues		(33,751	)		(81,557	)		(109,895	)

Total consolidated revenues	$	415,244		$	344,833		$	295,919

Operating income:
Operating income	$	68,773		$	50,779		$	43,461
Interest income		639			3,118			6,565
Interest expense, net		(16,241	)		(14,945	)		(29,745	)
Foreign currency translation and transaction gains (losses)		1,107			(7,721	)		(1,339	)
Income attributable to sale of tax benefits		15,515			18,118			6,488
Gain from extinguishment of liability		13,348			—			—
Other non-operating income (expense), net		200			(3,424	)		(1,130	)

Total consolidated income before income taxes and equity in income of investees	$	83,341		$	45,925		$	24,300

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,
	2009		2008		2007
	(Dollars in thousands)

Revenues from external customers attributable to: ⁽¹⁾
North America	$	248,357	$	252,557	$	236,273
Pacific Rim		32,158		21,258		11,420
Latin America		79,683		33,874		26,193
Africa		34,857		10,704		9,896
Far East		3,850		6,030		1,400
Europe		16,339		20,410		10,737

Consolidated total	$	415,244	$	344,833	$	295,919


⁽¹⁾		Revenues as reported in the geographic area in which they originate.

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	December 31,
	2009		2008 (As Restated)		2007
	(Dollars in thousands)

Long-lived assets (primarily power plants and related
assets) located in:
North America	$	1,341,863	$	1,181,714	$	811,828
Latin America		80,687		94,464		99,178
Africa		131,997		113,157		113,410
Europe		12,846		9,572		7,273
Pacific Rim and Far East		12,816		9,873		7,744

Consolidated total	$	1,580,209	$	1,408,780	$	1,039,433

The following table presents revenues from major customers:


	Year Ended December 31,
	2009				2008				2007
	Revenues		%		Revenues		%		Revenues		%
	(Dollars in				(Dollars in				(Dollars in
	thousands)				thousands)				thousands)

SCE ⁽¹⁾	$	87,017		21.0	$	95,254		27.6	$	94,430		31.9
Hawaii Electric Light Company ⁽¹⁾		25,979		6.3		57,679		16.7		43,087		14.6
Sierra Pacific Power Company and
Nevada Power Company ⁽¹⁾⁽²⁾		53,658		12.9		43,406		12.6		32,159		10.9
NGP Blue Mountain I LLC ⁽³⁾		46,893		11.3		32,646		9.5		—		—
Central American Bank for Economic
Integration (Las Pailas Project) ⁽³⁾		44,073		10.6		—		—		—		—


⁽¹⁾		Revenues reported in Electricity Segment.

⁽²⁾		Subsidiaries of NV Energy, Inc.

⁽³⁾		Revenues reported in Product Segment.


NOTE 18 —	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,
	2009		2008		2007
	(Dollars in thousands)

Property rental fee expense paid to the Parent	$	1,380	$	656	$	654

Interest expense on note payable to Parent	$	1,125	$	3,597	$	5,941

Corporate financial, administrative, executive services, and research and development services provided to the Parent	$	170	$	152	$	131

Services rendered by an indirect shareholder of the Parent	$	91	$	110	$	142

The current liability due from Parent at December 31, 2009 and 2008 of $422,000 and $1,085,000, 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%

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(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.

Notes payable to Parent

The Company has a loan agreement with the Parent (“Parent Loan Agreement”) pursuant to which the Company may borrow from the Parent up to $150 million in one or more advances. Interest accrues on the unpaid principal of the loan amount at a rate per annum of the Parent’s average effective interest plus 0.3% (7.5%). The principal and interest on the Parent Loan Agreement are payable in varying amounts through the loan due date of June 2010. The outstanding balance of such loan at December 31, 2009 and 2008 was $9,600,000 (which represents the current portion) and $26,200,000 (including current portion of $16,600,000), respectively.

The notes will be fully repaid in the year ending December 31, 2010.

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 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, subject to approval by the Israel Land Administration. 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 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, officer and employees against liability that may result from their sale of the Company’s common stock, including Securities Act liabilities.


NOTE 19 —	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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 $364,000, $301,000, and $264,000 for the years ended December 31, 2009, 2008, and 2007, 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 accounted for using what is commonly referred to as the “shut down” method, where a company records the undiscounted obligation as if it were payable at each balance sheet date. Such liabilities have been presented on 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 $16,274,000 and $14,884,000 at December 31, 2009 and 2008, respectively, and have been presented on 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, 2009, 2008, and 2007 were $2,304,000, $2,843,000, and $2,734,000, respectively, which includes income amounting to $1,613,000, $324,000, and $722,000, respectively, generated from the regular deposits and amounts accrued in severance funds

The Company expects the severance pay contributions in 2010 to be approximately $1.5 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:
2010	$	3,161
2011		1,040
2012		587
2013		717
2014		643
2015-2019		7,873

	$	14,021

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 20 —	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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Royalty expense under the geothermal resource agreements were $6,611,000, $10,737,000, and $8,370,000 for the years ended December 31, 2009, 2008, and 2007, 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 $53.4 million and $23.4 million at December 31, 2009 and 2008, respectively. 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, 2009, total obligations related to such supplier agreements were approximately $42.1 million (out of which approximately $29.4 million relate to construction-in-process). All such obligations are payable in 2010.

Grants and royalties

The Company, through Ormat Systems, has 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, 2009, 2008 and 2007. The Company is not liable for royalties if the Company does not sell the respective products. Such royalties are capped at the amount of the grants received plus interest at LIBOR. The cap at December 31, 2009 and 2008, amounted to $1,284,000 and $1,200,000, respectively, of which approximately $343,000 and $260,000 of the cap, respectively, increases based on the LIBOR rate, as defined.

Contingencies

The Company is a defendant in various other legal and regulatory proceedings in the ordinary course of business. It is the opinion of the Company’s management that the expected outcome of these matters, individually or in the aggregate, will not have a material effect on the financial position, results of operations and cash flows of the Company.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


NOTE 21 —	QUARTERLY FINANCIAL INFORMATION (UNAUDITED)


	Three Months Ended
	March 31,			June 30,			Sept. 30,			Dec. 31,			March 31,			June 30,			Sept. 30,			Dec. 31,
	2008			2008			2008			2008 (As Restated) ⁽¹⁾⁽²⁾			2009			2009			2009 (As Revised) ⁽³⁾			2009 ⁽⁴⁾
	(Dollars in thousands, except per share amounts)

Revenues:
Electricity Segment	$	59,519		$	61,774		$	68,837		$	62,126		$	62,638		$	60,562		$	68,715		$	63,940
Products Segment		9,868			18,447			30,889			33,373			37,251			39,673			51,113			31,352

		69,387			80,221			99,726			95,499			99,889			100,235			119,828			95,292

Cost of revenues:
Electricity Segment		38,676			41,506			44,742			45,129			43,884			44,958			44,394			46,920
Products Segment		8,050			15,704			23,730			25,271			24,243			27,242			35,780			25,185

		46,726			57,210			68,472			70,400			68,127			72,200			80,174			72,105

Gross margin		22,661			23,011			31,254			25,099			31,762			28,035			39,654			23,187
Operating expenses:
Research and development expenses		696			785			1,894			1,220			801			2,487			3,863			3,351
Selling and marketing expenses		3,519			2,020			2,647			2,699			4,301			3,215			3,393			3,675
General and administrative expenses		6,027			5,925			7,587			6,399			7,535			5,582			6,437			6,858
Write-off of unsuccessful exploration activities		—			—			—			9,828			—			—			2,367			—

Operating income		12,419			14,281			19,126			4,953			19,125			16,751			23,594			9,303
Other income (expense):
Interest income		1,046			1,052			637			383			151			276			158			54
Interest expense, net		(4,786	)		(4,851	)		(3,017	)		(2,291	)		(3,290	)		(4,415	)		(4,358	)		(4,178	)
Foreign currency translation and transaction gain (loss)		(183	)		(1,359	)		(1,028	)		(5,151	)		(2,560	)		2,569			1,320			(222	)
Impairment of auction rate securities		(328	)		—			(2,045	)		(1,822	)		(279	)		—			—			—
Income attributable to sale of tax benefits		3,316			4,848			4,995			4,959			4,168			4,366			3,869			3,112
Gain from extinguishment of liability		—			—			—			—			—			—			—			13,348
Other non-operating income (expense), net		40			309			(21	)		443			130			550			245			(446	)

Income before income taxes, and equity in income of investees		11,524			14,280			18,647			1,474			17,445			20,097			24,828			20,971
Income tax benefit (provision)		(2,071	)		(2,613	)		(3,187	)		3,513			(3,489	)		(4,478	)		(3,472	)		(5,485	)
Equity in income of investees		539			408			372			406			550			355			591			640

Net income		9,992			12,075			15,832			5,393			14,506			15,974			21,947			16,126
Net loss attributable to noncontrolling interest		72			86			79			79		$	79		$	77		$	80		$	62

Net income attributable to the Company’s stockholders	$	10,064		$	12,161		$	15,911		$	5,472		$	14,585		$	16,051		$	22,027		$	16,188

Earnings per share — basic and diluted
Basic	$	0.24		$	0.28		$	0.35		$	0.12		$	0.32		$	0.35		$	0.49		$	0.36

Diluted	$	0.24		$	0.28		$	0.35		$	0.12		$	0.32		$	0.35		$	0.48		$	0.35

Weighted average number of shares used in computation of earnings per share:
Basic		42,163			43,828			45,337			45,347			45,353			45,369			45,413			45,426

Diluted		42,271			43,978			45,483			45,423			45,405			45,451			45,564			45,623


⁽¹⁾		Included in income tax benefit (provision) for the three month period ended December 31, 2008 is an out-of-period adjustment of $835,000 that increased income tax provision. Such adjustment related to uncertain tax positions taken in 2004 to 2007.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


⁽²⁾		The effect of the restatement described in Note 1 on the financial statements for the three months ended December 31, 2008 is as follows:


							As Restated Before
							Application of New			Application of New
	As Originally			Restatement			Accounting			Accounting
	Reported			Adjustment			Standard			Standard			As Restated
	(Dollars in thousands)

Write-off of unsuccessful exploration activities	$	—		$	(9,828	)	$	(9,828	)	$	—		$	(9,828	)

Operating income		14,781			(9,828	)		4,953			—			4,953
Other income (expense): Interest income		383						383						383
Interest expense, net		(348	)					(348	)		(1,943	)		(2,291	)
Foreign currency translation and transaction losses		(5,151	)		—			(5,151	)					(5,151	)
Income attributable to sale of tax benefits		—			—			—			4,959			4,959
Other non-operating expense, net		(1,379	)		—			(1,379	)		—			(1,379	)

Income before income taxes, minority interest and equity in income of investees		8,286			(9,828	)		(1,542	)		3,016			1,474
Income tax benefit (provision)		(91	)		3,604			3,513			—			3,513
Minority interest		3,095			—			3,095			(3,095	)		—
Equity in income of investees, net		406			—			406			—			406

Net income		11,696			(6,224	)		5,472			(79	)		5,393
Net loss attributable to noncontrolling interest		—			—			—			79			79

Net income attributable to the Company’s stockholders	$	11,696		$	(6,224	)	$	5,472		$	—		$	5,472


⁽³⁾		The Company revised its financial statements for the three-month period ended September 30, 2009 to give effect to a write-off of costs associated with a project which the Company determined in the third quarter of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		2009 would not support commercial operations. The effect of the revision on the results of operations in that period is as follows:


	As Originally
	Reported			Adjustment			As Revised
	(Dollars in thousands)

Write-off of unsuccessful exploration activities	$	—		$	(2,367	)	$	(2,367	)

Operating income		25,961			(2,367	)		23,594
Other income (expense): Interest income		158			—			158
Interest expense, net		(4,358	)		—			(4,358	)
Foreign currency translation and transaction gains		1,320			—			1,320
Income attributable to sale of tax benefits		3,869			—			3,869
Other non-operating income, net		245			—			245

Income before income taxes and equity in income of investees		27,195			(2,367	)		24,828
Income tax provision		(4,340	)		868			(3,472	)
Equity in income of investees, net		591			—			591

Net income		23,446			(1,499	)		21,947
Net loss attributable to noncontrolling interest		80			—			80

Net income attributable to the Company’s stockholders	$	23,526		$	(1,499	)	$	22,027


⁽⁴⁾		Included in income tax benefit (provision) for the three months ended December 31, 2009 is an out-of-period adjustment of $884,000 that increased income tax provision. Such adjustment related to tax positions taken in 2002 to 2008.


NOTE 22 —	SUBSEQUENT EVENTS

Transfer of shares in GDL

On January 13, 2010, a former shareholder of GDL exercised a call option to purchase from the Company its shares in GDL for approximately $2.6 million. The Company did not exercise its right of first refusal and therefore the Company transferred its shares in GDL to the former shareholder. As a result, the Company will record a pre-tax gain of approximately $6.0 million in the first quarter of 2010.

Cash dividend

On February 23, 2010, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $5.5 million ($0.12 per share) to all holders of the Company’s issued and outstanding shares of common stock on March 16, 2010, payable on March 25, 2010.

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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, 2009, that the disclosure controls and procedures were effective in ensuring that all material information required to be filed in this Annual Report on Form 10-K 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, 2009 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, 2009.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2009 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.

Management’s Consideration of the Restatement

In connection with the restatement of the Company’s 2008 financial statements set forth in this Form 10-K, management evaluated if the use of an inappropriate accounting method for exploration and development costs during the years ended December 31, 2009 and 2008 was indicative of a deficiency in internal control over financial reporting. Management of the Company concluded that a deficiency in internal control over financial reporting did not exist. In reaching this conclusion, management considered the results of its overall assessment of the Company’s financial reporting process and controls as well as the specific procedures and controls undertaken by management to evaluate the application of generally accepted accounting principles in determining the appropriate accounting method for exploration and development costs incurred related to the Company’s geothermal development

180

activities. Management performed a thorough, well-reasoned evaluation when selecting its accounting policy for exploration and development costs which included an evaluation of existing authoritative accounting guidance as well as reviewing the accounting policies disclosed by other public geothermal companies in the U.S.


ITEM 9B.	*OTHER INFORMATION*

None.

PART III


ITEM 10.	*DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT*

Information required by this Item in addition to that below is incorporated by reference herein from the Company’s definitive 2010 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

Lucien Bronicki		76	Chairman of the Board of Directors; Chief Technology Officer(3)
Yehudit “Dita” Bronicki		68	Chief Executive Officer; Director(2)
Yoram Bronicki		43	President; Chief Operating Officer; Director(1)
Joseph Tenne		54	Chief Financial Officer*
Nadav Amir		59	Executive Vice President — Operations*
Zvi Reiss		59	Executive Vice President — Project Management*
Joseph Shiloah		64	Executive Vice President — Marketing and Sales, Rest of the World*
Zvi Krieger		54	Executive Vice President — Geothermal Resource*
Shimon Hatzir		48	Senior Vice President — Engineering*
Etty Rosner		54	Senior Vice President — Contract Management; Corporate Secretary*
Independent Directors:
Dan Falk		65	Independent Director ⁽³⁾
Roger W. Gale		63	Independent Director ⁽¹⁾
Robert F. Clarke		67	Independent Director ⁽²⁾
David Wagener†		55	Independent Director ⁽²⁾


*		Performs the functions described in the table, but is employed by Ormat Systems.

†		David Wagener has been appointed to the Board, effective as of April 1, 2010, to fill the vacancy resulting from Jacob Worenklein’s resignation, effective as of March 31, 2010.


⁽¹⁾		Denotes Class I Director — Term expiring at 2011 Annual Shareholders Meeting.

⁽²⁾		Denotes Class II Director — Term expiring at 2012 Annual Shareholders Meeting.

⁽³⁾		Denotes Class III Director — Term expiring at 2010 Annual Shareholders Meeting.

Lucien Bronicki. Lucien Bronicki is the Chairman of our Board of Directors, a position he has held since our inception in 1994, and has also been our Chief Technology Officer since July 1, 2004. Mr. Bronicki co-founded Ormat Turbines Ltd. in 1965 and is the Chairman of the Board of Directors of Ormat Industries Ltd., the publicly-traded successor to Ormat Turbines Ltd., and several of its subsidiaries. From 1999 to April 2006, Mr. Bronicki served as the Chairman of the Board of Directors of OPTI Canada Inc., a company engaged in the oil sands industry

181

in Canada in which our parent owns an approximately 5% interest. 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. 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. 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 Metiers, a Master of Science in Physics from Universite de Paris and a Master of Science in Mechanical Engineering from Ecole Nationale Superieure d’Ingenieurs Arts et Metiers. In the year 2005, he received a Ph.D. Honoris Causa from the Ben-Gurion University, and in 2006 from the Weizmann Institute of Science.

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 she was also our President. Mrs. Bronicki was also 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, Mrs. Bronicki was a member of the Board of Directors of OPTI Canada Inc. until May 2005 and since 2000, 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.

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 is also a member of the Board of Directors of Ormat Industries Ltd., a position he has held since 2001, and a member of the Board of Directors of OPTI Canada Inc. From 2001 to 2004, Mr. Bronicki was Vice President of OPTI Canada Inc.; from 1999 to 2001, he 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.

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 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 Technion Haifa 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

182

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.

Joseph Shiloah. Joseph Shiloah has served as our Executive Vice President of Marketing and Sales, Rest of the World, since July 1, 2004. From 2001 to June 30, 2004, Mr. Shiloah was the Executive Vice President of Marketing and Sales at Ormat Industries Ltd.; from 1989 to 2000, he was Vice President of Marketing and Sales of Ormat Industries Ltd.; from 1983 to 1989, he was Vice President of Special Projects of Ormat Turbines Ltd.; from 1984 to 1989, he was Operating Manager of the Solar Pond project of Solmat Systems Ltd., a subsidiary of Ormat Turbines Ltd.; and from 1981 to 1983, he was Project Administrator of the Solar Pond power plant project of Ormat Turbines Ltd. and Solmat Systems Ltd. Mr. Shiloah obtained a Bachelor of Arts in Economics from Hebrew University in Jerusalem in 1972.

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; and 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.

Dan Falk. Dan Falk has been a member of our Board of Directors since November 12, 2004. Mr. Falk is also the Chairman of the Board of Directors of Orad Hi-Tech Systems Ltd., a public non-US company, and of Chromagen Ltd., a private non-U.S. company. He is also a member of the Board of Directors of Orbotech Ltd., Nice Systems Ltd., Attunity Ltd., Jacada 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-US companies: AVT Ltd., Amiad Filteration System Ltd, Plastopil Ltd., and Oridion Medical Ltd. During the past five years, Mr. Falk served as a member of the Board of the Directors of the following public companies, for which he no longer serves as a Director: Clicksoftware Technologies Ltd., Dmatek Ltd., Poalim Ventures I Ltd., Dor Chemicals Ltd., Medcon Ltd., and Ramdor 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 NV. 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 of Orbotech Ltd. Mr. Falk obtained a Master 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. Our Board of Directors has determined that Mr. Falk qualifies as an Audit Committee “financial

183

expert” under Section 407 of the Sarbanes-Oxley Act of 2002 and Item 407(d)(5) of Regulation S-K, and is “independent” as that term is used in Item 407(d) 5(i)(B) of Regulation S-K under the Securities Exchange Act of 1934.

Roger W. Gale, Ph.D. Roger W. Gale has been a member of our Board of Directors since October 26, 2005. Between 1988 and 2000, Dr. Gale was the CEO of Washington International Energy Group, which was sold to PHB Hagler Bailly (PHB) in 1999. In 2000, as PHB was sold to PA Consulting, Dr. Gale held several positions at PA Consulting until 2001, at which time he joined GF Energy LLC as President and CEO, a position he still holds. In addition, Dr. Gale serves as a member of the Board of Directors of the US Energy Association, a not-for-profit organization. On December 1, 2005, he became a member of the Boards of Directors of The Adams Express Company and Petroleum & Energy Resources Corporation (closed-end investment companies). He served on the Audit Committee of Constellation Holdings and on the board of the parent, Constellation Energy Group from 1996 to 2005. Dr. Gale has a Ph.D. in political science from the University of California, Berkeley.

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, as a member of the advisory board of the Shidler College of Business at the University of Hawaii. and as a member of the advisory board of Sennet Capital. 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.

David Wagener. David Wagener will begin serving as a member of our Board of Directors on April 1, 2010. Since June 1995, Mr. Wagener has been the Managing Partner of Wagener Capital Management. From 1990 to 1995, Mr. Wagener served as director of the Public Utility & Telecommunications Group in the Investment Banking Division of Salomon Brothers, and from 1980 to 1990, he was Vice President of the Public Utility Group and Co-Head of the Independent Power Group in the Investment Banking Division of Goldman Sachs & Co. Mr. Waggener serves on the Board of Directors of Centennial Power, a subsidiary of MDU Resources, and on the Board of Directors of Primary Energy, the parent of Primary Energy Recycling. He received his Bachelor’s degree in 1976 from Harvard College, and his Master’s degree in Business Administration in 1980 from the University of Chicago.

Audit Committee

We are a listed issuer, as defined in Sec. 240.10A-3 of Regulation S-K, and have a separately designated audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act, composed of independent directors as required by Section 303A.07 of the NYSE Listed Company Manual. The members of such committee are Dan Falk (Chair), Roger W. Gale, and Robert Clarke who are also independent directors of our company, as defined in Section 303A.02 of the NYSE Listed Company Manual.


ITEM 11.	*EXECUTIVE COMPENSATION*

The information required under this item is incorporated by reference herein from the Company’s definitive 2010 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 2010 Proxy Statement.

184


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 2010 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 2010 Proxy Statement.

PART IV


ITEM 15.	*EXHIBITS, FINANCIAL STATEMENT SCHEDULES*

(a) (1) List of Financial Statements

See Index to Financial Statements in Item 8 of this annual report.

(2) List of Financial Statement Schedules

All applicable schedule information is included in our Financial Statements in Item 8 of this annual report.

(b) 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.

185


Exhibit
No.			Document

	10	.1.1	Credit Facility Agreement, dated September 5, 2000, between Ormat Momotombo Power Company and Bank Hapoalim B.M., incorporated by reference to Exhibit 10.1.3 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	.1.2	Credit Agreement, dated as of December 18, 2003, among OrCal Geothermal Inc. and Beal Bank, S.S.B. and the financial institutions party thereto from time to time, incorporated by reference to Exhibit 10.1.5 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	.1.3	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	.1.4	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	.1.5	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	.1.6	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	.1.7	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	.1.8	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	.1.9	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	.1.10	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	.1.11	Agreement for Purchase of Membership Interests in OPC LLC dated June 7, 2007, by and among Ormat Nevada Inc., Morgan Stanley Geothermal LLC and Lehman-OPC LLC, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on June 13, 2007.
	10	.1.12	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.

186


Exhibit
No.			Document

	10	.1.13	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.
	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 Exhibit 10.3.11 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.

187


Exhibit
No.			Document

	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.
	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.

188


Exhibit
No.			Document

	10	.2.25	IID-SIGC Transmission Service Agreement for Alternative Resources, dated, October 27, 1992, by and between Imperial Irrigation District and Second Imperial Geothermal Company incorporated by reference to Exhibit 10.3.25 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
	10	.2.26	Plant Connection Agreement for the Ormesa Geothermal Plant, dated October 1, 1985, by and between Imperial Irrigation District and Ormesa Geothermal incorporated by reference to Exhibit 10.3.26 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.27	Plant Connection Agreement for the Ormesa IE Geothermal Plant, dated, October 21, 1988, by and between Imperial Irrigation District and Ormesa IE incorporated by reference to Exhibit 10.3.27 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.28	Plant Connection Agreement for the Ormesa IH Geothermal Plant, dated, October 3, 1989, by and between Imperial Irrigation District and Ormesa IH incorporated by reference to Exhibit 10.3.28 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.29	Plant Connection Agreement for the Geo East Mesa Limited Partnership Unit No. 2, dated, March 21, 1989, by and between Imperial Irrigation District and Geo East Mesa Limited Partnership incorporated by reference to Exhibit 10.3.29 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.30	Plant Connection Agreement for the Geo East Mesa Limited Partnership Unit No. 3, dated, March 21, 1989, by and between Imperial Irrigation District and Geo East Mesa Limited Partnership incorporated by reference to Exhibit 10.3.30 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.31	Transmission Service Agreement for the Ormesa I, Ormesa IE and Ormesa IH Geothermal Power Plants, dated, October 3, 1989, between Imperial Irrigation District and Ormesa Geothermal incorporated by reference to Exhibit 10.3.31 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.32	Transmission Service Agreement for the Geo East Mesa Limited Partnership Unit No. 2, dated, March 21, 1989, by and between Imperial Irrigation District and Geo East Mesa Limited Partnership incorporated by reference to Exhibit 10.3.32 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	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.

189


Exhibit
No.			Document

	10	.2.37	Amendment No. 1 to Agreement Addressing Renewable Energy Pricing and Payment Issues, dated November 30, 2001, by and between Second Imperial Geothermal Company QFID No. 3021 and Southern California Edison Company incorporated by reference to Exhibit 10.3.40 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.38	Agreement Addressing Renewable Energy Pricing and Payment Issues, dated June 15, 2001, by and between Heber Geothermal Company QFID No. 3001 and Southern California Edison Company incorporated by reference to Exhibit 10.3.41 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.39	Amendment No. 1 to Agreement Addressing Renewable Energy Pricing and Payment Issues, dated November 30, 2001, by and between Heber Geothermal Company QFID No. 3001 and Southern California Edison Company incorporated by reference to Exhibit 10.3.42 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.40	Energy Services Agreement, dated February 2003, by and between Imperial Irrigation District and ORMESA, LLC incorporated by reference to Exhibit 10.3.43 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.41	Purchase Power Contract, dated March 24, 1986, by and between Hawaii Electric Light Company and Thermal Power Company incorporated by reference to Exhibit 10.3.44 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.42	Firm Capacity Amendment to Purchase Power Contract, dated July 28, 1989, by and between Hawaii Electric Light Company and Puma Geothermal Venture incorporated by reference to Exhibit 10.3.45 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.43	Amendment to Purchase Power Contract, dated October 19, 1993, by and between Hawaii Electric Light Company and Puma Geothermal Venture incorporated by reference to Exhibit 10.3.46 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.44	Third Amendment to the Purchase Power Contract, dated March 7, 1995, by and between Hawaii Electric Light Company and Puna Geothermal Venture incorporated by reference to Exhibit 10.3.47 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.45	Performance Agreement and Fourth Amendment to the Purchase Power Contract, dated February 12, 1996, by and between Hawaii Electric Light Company and Puna Geothermal Venture incorporated by reference to Exhibit 10.3.48 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.46	Agreement to Design 69 KV Transmission Lines, a Substation at Pohoiki, Modifications to Substations at Puna and Kaumana, and a Temporary 34.5 Facility to Interconnect PGV’s Geothermal Electric Plant with HELCO’s System Grid (Phase II and III), dated June 7, 1990, by and between Hawaii Electric Light Company and Puna Geothermal Venture incorporated by reference to Exhibit 10.3.49 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004
	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.

190


Exhibit
No.			Document

	10	.3.3	Geothermal Resources Mining Lease, dated February 20, 1981, by and between the State of Hawaii, as Lessor, and Kapoho Land Partnership, as Lessee incorporated by reference to Exhibit 10.4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.4	Geothermal Lease Agreement, dated October 20, 1975, by and between Ruth Walker Cox and Betty M. Smith, as Lessor, and Gulf Oil Corporation, as Lessee incorporated by reference to Exhibit 10.4.4 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.5	Geothermal Lease Agreement, dated August 1, 1976, by and between Southern Pacific Land Company, as Lessor, and Phillips Petroleum Company, as Lessee incorporated by reference to Exhibit 10.4.5 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.6	Geothermal Resources Lease, dated November 18, 1983, by and between Sierra Pacific Power Company, as Lessor, and Geothermal Development Associates, as Lessee incorporated by reference to Exhibit 10.4.6 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.7	Lease Agreement, dated November 1, 1969, by and between Chrisman B. Jackson and Sharon Jackson, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.7 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
	10	.3.8	Lease Agreement, dated September 22, 1976, by and between El Toro Land & Cattle Co., as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.8 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
	10	.3.9	Lease Agreement, dated February 17, 1977, by and between Joseph L. Holtz, as Lessor, and Chevron U.S.A. Inc., as Lessee incorporated by reference to Exhibit 10.4.9 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
	10	.3.10	Lease Agreement, dated March 11, 1964, by and between John D. Jackson and Frances Jones Jackson, also known as Frances J. Jackson, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.10 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
	10	.3.11	Lease Agreement, dated February 16, 1964, by and between John D. Jackson, conservator for the estate of Aphia Jackson Wallan, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.11 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
	10	.3.12	Lease Agreement, dated March 17, 1964, by and between Helen S. Fugate, a widow, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.12 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.13	Lease Agreement, dated February 16, 1964, by and between John D. Jackson and Frances J. Jackson, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.13 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.14	Lease Agreement, dated February 20, 1964, by and between John A. Straub and Edith D. Straub, also known as John A. Straub and Edythe D. Straub, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.14 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

191


Exhibit
No.			Document

	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.
	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.

192


Exhibit
No.			Document

	10	.3.26	Geothermal Resources Lease, dated June 27, 1988, by and between Bernice Guisti, Judith Harvey and Karen Thompson, Trustees and Beneficiaries of the Guisti Trust, as Lessor, and Far West Capital, Inc., as Lessee incorporated by reference to Exhibit 10.4.26 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.27	Amendment to Geothermal Resources Lease, dated January, 1992, by and between Bernice Guisti, Judith Harvey and Karen Thompson, Trustees and Beneficiaries of the Guisti Trust, as Lessor, and Far West Capital, Inc., as Lessee incorporated by reference to Exhibit 10.4.27 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.28	Second Amendment to Geothermal Resources Lease, dated June 25, 1993, by and between Bernice Guisti, Judith Harvey and Karen Thompson, Trustees and Beneficiaries of the Guisti Trust, as Lessor, and Far West Capital, Inc. and its Assignee, Steamboat Development Corp., as Lessee incorporated by reference to Exhibit 10.4.28 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.29	Geothermal Resources Sublease, dated May 31, 1991, by and between Fleetwood Corporation, as Lessor, and Far West Capital, Inc., as Lessee incorporated by reference to Exhibit 10.4.29 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	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.

193


Exhibit
No.			Document

	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	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	.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	.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	.9	Form of Indemnification Agreement incorporated by reference to Exhibit 10.11 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 20, 2004.
	10	.10	Note Purchase Agreement, dated December 2, 2005, among Lehman Brothers Inc., OrCal Geothermal Inc., OrHeber 1 Inc., OrHeber 2 Inc., Second Imperial Geothermal Company, Heber Field Company and Heber Geothermal Company, incorporated by reference to Exhibit 10.12 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 28, 2006.
	10	.11.1	Indenture dated as of December 8, 2005 among OrCal Geothermal Inc., OrHeber 1 Inc., OrHeber 2 Inc., Second Imperial Geothermal Company, Heber Field Company and Heber Geothermal Company and Union Bank of California, incorporated by reference to Exhibit 10.13 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 28, 2006.
	10	.11.2	First Supplemental Indenture dated as of June 14, 2006 amending the Indenture dated as of December 8, 2005 among OrCal Geothermal Inc., OrHeber 1 Inc., OrHeber 2 Inc., Second Imperial Geothermal Company, Heber Field Company and Heber Geothermal Company and Union Bank of California, incorporated by reference to Exhibit 10.13.2 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q (File No 001-32347) to the Securities and Exchange Commission on August 7, 2006.
	10	.12	Guarantee dated as of December 8, 2005 among OrCal Geothermal Inc., OrHeber 1 Inc., OrHeber 2 Inc., Second Imperial Geothermal Company, Heber Field Company and Heber Geothermal Company, incorporated by reference to Exhibit 10.14 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 28, 2006.
	10	.13	Note Purchase Agreement, dated February 6, 2004, among Lehman Brothers Inc., Ormat Funding Corp., Brady Power Partners, Steamboat Geothermal LLC, OrMammoth Inc., ORNI 1 LLC, ORNI 2 LLC and ORNI 7 LLC, incorporated by reference to Exhibit 10.15 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 28, 2006.

194


Exhibit
No.			Document

	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.
	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.

195


Exhibit
No.			Document

	10	.20.1	Subscription Agreement dated as of October 22, 2007 between the Company and Ormat Industries Ltd., incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on October 24, 2007.
	10	.20.2	Amendment No. 1 to the Subscription Agreement, dated October 25, 2007, between the Company and Ormat Industries Ltd., incorporated by reference to Exhibit 1.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on October 31, 2007.
	10	.21	Subscription Agreement dated as of December 3, 2007 between the Company and Ormat Industries Ltd., incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on January 9, 2008.
	10	.22	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	.23	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.
	21	.1	Subsidiaries of Ormat Technologies, Inc., incorporated by reference to Exhibit 21.1 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 28, 2006
	23	.1	Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm, filed herewith.
	31	.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
	31	.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
	32	.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.
	32	.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.
	99	.1	Material terms with respect to BLM geothermal resources leases incorporated by reference to Exhibit 99.1 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 20, 2004.
	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.

196

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 8, 2010

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 8, 2010.


	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/ LUCIEN Y. BRONICKI Lucien Y. Bronicki		Chairman of the Board of Directors and Chief Technology Officer

/s/ YORAM BRONICKI Yoram Bronicki		President, Chief Operating Officer and Director

/s/ DAN FALK Dan Falk		Director

197


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.
	10	.1.1	Credit Facility Agreement, dated September 5, 2000, between Ormat Momotombo Power Company and Bank Hapoalim B.M., incorporated by reference to Exhibit 10.1.3 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	.1.2	Credit Agreement, dated as of December 18, 2003, among OrCal Geothermal Inc. and Beal Bank, S.S.B. and the financial institutions party thereto from time to time, incorporated by reference to Exhibit 10.1.5 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	.1.3	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	.1.4	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	.1.5	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.

198


Exhibit
No.			Document

	10	.1.6	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	.1.7	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	.1.8	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	.1.9	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	.1.10	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	.1.11	Agreement for Purchase of Membership Interests in OPC LLC dated June 7, 2007, by and among Ormat Nevada Inc., Morgan Stanley Geothermal LLC and Lehman-OPC LLC, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on June 13, 2007.
	10	.1.12	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	.1.13	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.

199


Exhibit
No.			Document

	10	.2.6	Settlement Agreement and Amendment No. 2, to Power Purchase Contract, dated August 7, 1995, between HGC and Southern California Edison Company, incorporated by reference to Exhibit 10.3.6 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.7	Power Purchase Contract dated, April 16, 1985, between Southern California Edison Company and Second Imperial Geothermal Company, incorporated by reference to Exhibit 10.3.7 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.8	Amendment No. 1, dated as of October 23, 1987, between Southern California Edison Company and Second Imperial Geothermal Company, incorporated by reference to Exhibit 10.3.8 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
	10	.2.9	Amendment No. 2, dated as of July 27, 1990, between Southern California Edison Company and Second Imperial Geothermal Company, incorporated by reference to Exhibit 10.3.9 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004
	10	.2.10	Amendment No. 3, dated as of November 24, 1992, between Southern California Edison Company and Second Imperial Geothermal Company, incorporated by reference to Exhibit 10.3.10 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
	10	.2.11	Amended and Restated Power Purchase and Sales Agreement, dated December 2, 1986, between Mammoth Pacific and Southern California Edison Company, incorporated by reference to Exhibit 10.3.11 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.

200


Exhibit
No.			Document

	10	.2.19	Interconnection Facilities Agreement, dated October 20, 1989, by and between Southern California Edison Company and Mammoth Pacific, incorporated by reference to Exhibit 10.3.19 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.20	Interconnection Facilities Agreement, dated October 13, 1985, by and between Southern California Edison Company and Mammoth Pacific (II), incorporated by reference to Exhibit 10.3.20 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.21	Interconnection Facilities Agreement, dated October 20, 1989, by and between Southern California Edison Company and Pacific Lighting Energy Systems, incorporated by reference to Exhibit 10.3.21 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.22	Interconnection Agreement, dated August 12, 1985, by and between Southern California Edison Company and Heber Geothermal Company incorporated by reference to Exhibit 10.3.22 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.23	Plant Connection Agreement for the Heber Geothermal Plant No. 1, dated, July 31, 1985, by and between Imperial Irrigation District and Heber Geothermal Company incorporated by reference to Exhibit 10.3.23 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.24	Plant Connection Agreement for the Second Imperial Geothermal Company Power Plant No. 1, dated, October 27, 1992, by and between Imperial Irrigation District and Second Imperial Geothermal Company incorporated by reference to Exhibit 10.3.24 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.25	IID-SIGC Transmission Service Agreement for Alternative Resources, dated, October 27, 1992, by and between Imperial Irrigation District and Second Imperial Geothermal Company incorporated by reference to Exhibit 10.3.25 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
	10	.2.26	Plant Connection Agreement for the Ormesa Geothermal Plant, dated October 1, 1985, by and between Imperial Irrigation District and Ormesa Geothermal incorporated by reference to Exhibit 10.3.26 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.27	Plant Connection Agreement for the Ormesa IE Geothermal Plant, dated, October 21, 1988, by and between Imperial Irrigation District and Ormesa IE incorporated by reference to Exhibit 10.3.27 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.28	Plant Connection Agreement for the Ormesa IH Geothermal Plant, dated, October 3, 1989, by and between Imperial Irrigation District and Ormesa IH incorporated by reference to Exhibit 10.3.28 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.29	Plant Connection Agreement for the Geo East Mesa Limited Partnership Unit No. 2, dated, March 21, 1989, by and between Imperial Irrigation District and Geo East Mesa Limited Partnership incorporated by reference to Exhibit 10.3.29 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.30	Plant Connection Agreement for the Geo East Mesa Limited Partnership Unit No. 3, dated, March 21, 1989, by and between Imperial Irrigation District and Geo East Mesa Limited Partnership incorporated by reference to Exhibit 10.3.30 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.2.31	Transmission Service Agreement for the Ormesa I, Ormesa IE and Ormesa IH Geothermal Power Plants, dated, October 3, 1989, between Imperial Irrigation District and Ormesa Geothermal incorporated by reference to Exhibit 10.3.31 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.

201


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.
	10	.2.42	Firm Capacity Amendment to Purchase Power Contract, dated July 28, 1989, by and between Hawaii Electric Light Company and Puna 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 Puna 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.

202


Exhibit
No.			Document

	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.
	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.

203


Exhibit
No.			Document

	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.
	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.

204


Exhibit
No.			Document

	10	.3.23	Geothermal Lease Agreement, dated February 15, 1977, by and between Walter J. Holtz, as Lessor, and Magma Energy Inc., as Lessee incorporated by reference to Exhibit 10.4.23 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.24	Geothermal Lease, dated August 31, 1983, by and between Magma Energy Inc., as Lessor, and Holt Geothermal Company, as Lessee incorporated by reference to Exhibit 10.4.24 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.25	Unprotected Lease Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd. incorporated by reference to Exhibit 10.4.25 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
	10	.3.26	Geothermal Resources Lease, dated June 27, 1988, by and between Bernice Guisti, Judith Harvey and Karen Thompson, Trustees and Beneficiaries of the Guisti Trust, as Lessor, and Far West Capital, Inc., as Lessee incorporated by reference to Exhibit 10.4.26 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.27	Amendment to Geothermal Resources Lease, dated January, 1992, by and between Bernice Guisti, Judith Harvey and Karen Thompson, Trustees and Beneficiaries of the Guisti Trust, as Lessor, and Far West Capital, Inc., as Lessee incorporated by reference to Exhibit 10.4.27 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.28	Second Amendment to Geothermal Resources Lease, dated June 25, 1993, by and between Bernice Guisti, Judith Harvey and Karen Thompson, Trustees and Beneficiaries of the Guisti Trust, as Lessor, and Far West Capital, Inc. and its Assignee, Steamboat Development Corp., as Lessee incorporated by reference to Exhibit 10.4.28 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.29	Geothermal Resources Sublease, dated May 31, 1991, by and between Fleetwood Corporation, as Lessor, and Far West Capital, Inc., as Lessee incorporated by reference to Exhibit 10.4.29 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	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.

205


Exhibit
No.			Document

	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	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	.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	.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	.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.

206


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.
	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.

207


Exhibit
No.			Document

	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	.20.1	Subscription Agreement dated as of October 22, 2007 between the Company and Ormat Industries Ltd., incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on October 24, 2007.
	10	.20.2	Amendment No. 1 to the Subscription Agreement, dated October 25, 2007, between the Company and Ormat Industries Ltd., incorporated by reference to Exhibit 1.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on October 31, 2007.
	10	.21	Subscription Agreement dated as of December 3, 2007 between the Company and Ormat Industries Ltd., incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on January 9, 2008.
	10	.22	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	.23	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.
	21	.1	Subsidiaries of Ormat Technologies, Inc., incorporated by reference to Exhibit 21.1 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 28, 2006.
	23	.1	Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm, filed herewith.
	31	.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
	31	.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
	32	.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.
	32	.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.
	99	.1	Material terms with respect to BLM geothermal resources leases incorporated by reference to Exhibit 99.1 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 20, 2004.
	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.

208

TABLE OF CONTENTS

Part I Item 1. Business Item 1A. Risk Factors Item 1B. Unresolved Staff Comments Item 2. Properties Item 3. Legal Proceedings Part II Item 5. Market For Registrant S Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity Securities Item 6. Selected Financial Data Item 7. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Financial Statements and Supplementary Data Note 1 Business and Significant Accounting Policies Note 2 Inventories Note 3 Cost and Estimated Earnings on Uncompleted Contracts Note 4 Unconsolidated Investments Note 5 Fair Value Of Financial Instruments Note 6 Property, Plant and Equipment and Construction-in-process Note 7 Intangible Assets Note 8 Accounts Payable and Accrued Expenses Note 9 Long-term Debt and Credit Agreements Note 10 Puna Power Plant Lease Transactions Note 11 Opc Transaction Note 12 Asset Retirement Obligation Note 13 Stock-based Compensation Note 14 Power Purchase Agreements Note 15 Interest Expense, Net Note 16 Income Taxes Note 17 Business Segments Note 18 Transactions with Related Entities Note 19 Employee Benefit Plan Note 20 Commitments and Contingencies Note 21 Quarterly Financial Information (unaudited)Note 22 Subsequent Events Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Item 9A. Controls and Procedures Item 9B. Other Information Part III Item 10. Directors and Executive Officers Of The Registrant Item 11. Executive Compensation Item 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13. Certain Relationships and Related Transactions, and Director Independence Item 14. Principal Accountant Fees and Services Part IV Item 15. Exhibits, Financial Statement Schedules

Exhibits

EX-23.1 EX-31.1 EX-31.2 EX-32.1 EX-32.2

ORA 10-K Fiscal year ended Dec. 31, 2009