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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, 2010
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 þ     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, 2010, 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 $515,567,617 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 February 24, 2011, 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, 2010.
 


 

 
ORMAT TECHNOLOGIES, INC.
 
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2010
 
TABLE OF CONTENTS
 
                 
        Page No.
 
PART I
 
ITEM 1.
    BUSINESS     9  
 
ITEM 1A.
    RISK FACTORS     66  
 
ITEM 1B.
    UNRESOLVED STAFF COMMENTS     83  
 
ITEM 2.
    PROPERTIES     83  
 
ITEM 3.
    LEGAL PROCEEDINGS     83  
 
PART II
 
ITEM 5.
    MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES     85  
 
ITEM 6.
    SELECTED FINANCIAL DATA     87  
 
ITEM 7.
    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS     88  
 
ITEM 7A.
    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK     120  
 
ITEM 8.
    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA     121  
 
ITEM 9.
    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE     181  
 
ITEM 9A.
    CONTROLS AND PROCEDURES     181  
 
ITEM 9B.
    OTHER INFORMATION     181  
 
PART III
 
ITEM 10.
    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE     182  
 
ITEM 11.
    EXECUTIVE COMPENSATION     185  
 
ITEM 12.
    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS     186  
 
ITEM 13.
    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE     186  
 
ITEM 14.
    PRINCIPAL ACCOUNTANT FEES AND SERVICES     186  
 
PART IV
 
ITEM 15.
    EXHIBITS, FINANCIAL STATEMENT SCHEDULES     186  
SIGNATURES
    198  


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Glossary of Terms
 
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
 
     
Term   Definition
 
Amatitlan Loan
  $42,000,000 in aggregate principal amount borrowed by our subsidiary Ortitlan from TCW Global Project Fund II, Ltd.
AMM
  Administrador del Mercado Mayorista (administrator of the wholesale market — Guatemala)
ARRA
  American Recovery and Reinvestment Act of 2009
Auxiliary Power
  The power needed to operate a geothermal power plant’s auxiliary equipment such as pumps and cooling towers.
Availability
  The ratio of the time a power plant is ready to be in service, or is in service, to the total time interval under consideration, expressed as a percentage, independent of fuel supply (heat or geothermal) or transmission accessibility.
Balance of Plant Equipment
  Power plant equipment other than the generating units including items such as transformers, valves, interconnection equipment, cooling towers for water cooled power plants, etc.
BLM
  Bureau of Land Management of the U.S. Department of the Interior
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
CGC
  Crump Geothermal Company LLC
CNE
  National Energy Commission of Nicaragua
CNEE
  National Electric Energy Commission of Guatemala
COD
  Commercial Operation Date
Company
  Ormat Technologies, Inc., a Delaware corporation, and subsidiaries
COSO
  Committee of Sponsoring Organizations of the Treadway Commission
CPI
  Consumer Price Index
CPUC
  California Public Utilities Commission
DEG
  Deutsche Investitions-und Entwicklungsgesellschaft mbH
DFIs
  Development Finance Institutions
DISNORTE
  Empresa Distribudora de Electricidad del Norte (a Nicaragua distribution company)
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
EBITDA
  Earnings before interest, taxes, depreciation and amortization
EGS
  Enhanced Geothermal Systems
EIS
  Environmental Impact Statement
ENATREL
  Empresa Nicaraguense de Transmision
ENEL
  Empresa Nicaraguense de Electricitdad
EPA
  U.S. Environmental Protection Agency


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Term   Definition
 
EPC
  Engineering, procurement and construction
EPS
  Earnings per share
ESC
  Energy Sales Contract
Exchange Act
  U.S. Securities Exchange Act of 1934, as amended
FASB
  Financial Accounting Standards Board
FERC
  U.S. Federal Energy Regulatory Commission
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
John Hancock
  John Hancock Life Insurance Company (U.S.A.)
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
Mammoth Pacific
  Mammoth-Pacific, L.P.
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
NGP
  Nevada Geothermal Power Inc.
NV Energy
  NV Energy, Inc.
NYSE
  New York Stock Exchange
OEC
  Ormat Energy Converter
OFC
  Ormat Funding Corp., a wholly owned subsidiary of the Company
OFC Senior Secured Notes
  81/4% Senior Secured Notes Due 2020 issued by OFC

4


 

     
Term   Definition
 
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
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:
     
    (CHART)
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
Orzunil
  Orzunil 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

5


 

     
Term   Definition
 
PUHCA
  U.S. Public Utility Holding Company Act of 1935
PUHCA 2005
  U.S. Public Utility Holding Company Act of 2005
PURPA
  U.S. Public Utility Regulatory Policies Act of 1978
Qualifying Facility(ies)
  Certain small power production facilities are eligible to be “Qualifying Facilities” under PURPA, provided that they meet certain power and thermal energy production requirements and efficiency standards. Qualifying Facility status provides an exemption from PUHCA 2005 and grants certain other benefits to the Qualifying Facility.
REG
  Recovered Energy Generation
RGGI
  Regional Greenhouse Gas Initiative
RPS
  Renewable Portfolio Standards
SCPPA
  Southern California Public Power Authority
SEC
  U.S. Securities and Exchange Commission
Senior Unsecured Bonds
  7% Senior Unsecured Bonds Due 2017 issued by the Company
Securities Act
  U.S. Securities Act of 1933, as amended
SOX Act
  Sarbanes-Oxley Act of 2002
Solar PV
  Solar photovoltaic
Southern California Edison
  Southern California Edison Company
SPE(s)
  Special purpose entity(ies)
SRAC
  Short Run Avoided Costs
Sunday Energy
  Sunday Energy Ltd.
U.S. Treasury
  U.S. Department of Treasury
Union Bank
  Union Bank, N.A.
U.S. 
  United States of America
W&M
  Watts & More Ltd.
WHOH
  Waste Heat Oil Heaters

6


 

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 Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in Part II, Item 1A — “Risk Factors” contained in Part I, and “Notes to Financial Statements” contained in Part II, Item 8 — “Financial Statements and Supplementary Data” contained in Part II of this annual report, but are found in other locations as well. These forward-looking statements generally relate to our plans, objectives and expectations for future operations and are based upon management’s current estimates and projections of future results or trends. Although we believe that our plans and objectives reflected in or suggested by these forward-looking statements are reasonable, we may not achieve these plans or objectives. You should read this annual report completely and with the understanding that actual future results and developments may be materially different from what we expect due to a number of risks and uncertainties, many of which are beyond our control. 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 incentives for the production of renewable energy at the federal and state level in the United States and elsewhere, and carbon-related legislation;
 
  •  changes in environmental and other laws and regulations to which our company is subject, as well as changes in the application of existing laws and regulations;
 
  •  current and future litigation;
 
  •  our ability to successfully identify, integrate and complete acquisitions;


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  •  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.


8


 

 
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.


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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 countries with projects under development and exploration.
 
(MAP)
 
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, 2010. 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”.


10


 

The following chart sets forth a breakdown of revenues for the year ended December 31, 2010:
 
(PIE CHART)
 
The following chart sets forth the geographical breakdown of the revenues attributable to our Electricity Segment for the year ended December 31, 2010:
 
(PIE CHART)


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The following chart sets forth the geographical breakdown of the revenues attributable to our Product Segment for the year ended December 31, 2010:
 
(PIE CHART)
 
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, solar thermal units and a variety of industrial processes, such as cement manufacturing. Such residual heat, which would otherwise be wasted, may be captured in the recovery process and used by recovered energy power plants to generate electricity without burning additional fuel and without additional emissions.
 
Company Contact and Sources of Information
 
We file annual, quarterly and periodic reports, proxy statements and other information with the SEC. You may obtain and copy any document we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington D.C. 20549. You may obtain information on the operation of the SEC’s Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and other information statements, and other information regarding issuers that file electronically with the SEC. Our SEC filings are accessible via the internet at that website.
 
Our reports on Form 10-K, 10-Q and 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available through our website at www.ormat.com for downloading, free of charge, as soon as reasonably practicable after these reports are filed with the SEC. Our Code of Business Conduct and Ethics, Code of Ethics Applicable to Senior Executives, Audit Committee Charter, Corporate Governance Guidelines, Nominating and Corporate Governance Committee Charter, Compensation Committee Charter, and Insider Trading Policy, as amended, are also available at our website address mentioned above. If we make any amendments to our Code of Business Conduct and Ethics or Code of Ethics Applicable to Senior


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Executives or grant any waiver, including any implicit waiver, from a provision of either code applicable to our Chief Executive Officer, Chief Financial Officer or principal accounting officer requiring disclosure under applicable SEC rules, we intend to disclose the nature of such amendment or waiver on our website. The content of our website, however, is not part of this annual report.
 
You may request a copy of our SEC filings, as well as the foregoing corporate documents, at no cost to you, by writing to the Company address appearing in this annual report or by calling us at (775) 356-9029.
 
Our Power Generation Business (Electricity Segment)
 
Power Plants in Operation
 
The table below summarizes certain key non-financial information relating to our power plants as of February 22, 2011:
 
                     
            Generating
            Capacity in
Power Plant   Location   Ownership(1)   MW(2)
 
Domestic
                   
Geothermal
                   
Brady Complex
  Nevada     100 %     23.0  
Heber Complex
  California     100 %     92.0  
Jersey Valley(3)
  Nevada     100 %     15.0  
Mammoth Complex
  California     100 %     29.0  
North Brawely(4)
  California     100 %     50.0  
Ormesa Complex
  California     100 %     54.0  
Puna
  Hawaii     100 %     30.0  
Steamboat Complex
  Nevada     100 %     89.0  
REG
                   
OREG 1
  North and South Dakota     100 %     22.0  
OREG 2
  Montana, North Dakota and Minnesota     100 %     22.0  
OREG 3
  Minnesota     100 %     5.5  
OREG 4
  Colorado     100 %     3.5  
                     
Total for domestic power plants
                435.0  
                     
Foreign
                   
Geothermal
                   
Amatitlan
  Guatemala     100 %     20.0  
Momotombo
  Nicaragua     (1)     26.0  
Olkaria III Complex
  Kenya     100 %     48.0  
Zunil
  Guatemala     100 %     24.0  
                     
Total for foreign power plants
                118.0  
                     
Total for all power plants
                553.0  
                     
 
 
(1) We own and operate all of our power plants other than the Momotombo power plant in Nicaragua, which we do not own but which we control and operate through a concession arrangement with the Nicaraguan government. Two financial institution hold 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 the above table, 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


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equity interests held by the financial institution is described in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations 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” obligation in the case of the PPA 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 2010, excluding the North Brawley power plant which operates at partial load, was approximately 90%. The Capacity Factor of the REG power plants in 2010 was approximately 70%.
 
(3) We completed the construction of the Jersey Valley power plant and placed it in service, but it is not yet in commercial operation under the PPA. Further information on the Jersey Valley power plant is provided under “Description of our Power Plants” below.
 
(4) The North Brawley power plant is not operating at full capacity. Detailed information on the North Brawley power plant is provided under “Description of our Power Plants” below.
 
Substantially all of the revenues that we currently derive from the sale of electricity are pursuant to long-term PPAs. Approximately 68.2% of our total revenues in the year ended December 31, 2010 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 our share of between 212 MW and 228 MW in generating capacity from geothermal power plants in the United States that are expected to come on-line in the next three years. In addition, we expect to add, in three phases, a total of approximately 42 MW, which is our share in the Sarulla project in Indonesia.
 
We have various leases and concessions for geothermal resources of approximately 343,000 acres in 27 sites. We have started or plan to start exploration activity at a number of these sites.
 
In addition, we have approximately 14 ground-mounted and roof-top Solar PV projects under development in Israel. Our share in these projects is 36 MW.
 
Our Product Business (Product Segment)
 
We design, manufacture and sell products for electricity generation and provide the related services described below. Generally, we manufacture products only against customer orders and do not manufacture products for our own inventory.
 
Power Units for Geothermal Power Plants.  We design, manufacture and sell power units for geothermal electricity generation, which we refer to as OECs. Our customers include contractors and geothermal power plant owners and operators.
 
Power Units for Recovered Energy-Based Power Generation.  We design, manufacture and sell power units used to generate electricity from recovered energy, or so-called “waste heat.” This heat is generated as a residual by-product of gas turbine-driven compressor stations, solar thermal units and a variety of industrial processes, such as cement manufacturing, and is not otherwise used for any purpose. Our existing and target customers include interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators, and other companies engaged in other energy-intensive industrial processes.


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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 60% of our outstanding common stock.
 
Industry Background
 
Geothermal Energy
 
Most of our power plants in operation produce electricity from geothermal energy. There are several different sources or methods to obtain geothermal energy, which are described below.
 
Hydrothermal geothermal-electricity generation — Hydrothermal geothermal energy is derived from naturally occurring hydrothermal reservoirs that are formed when water comes sufficiently close to hot rock to heat the water to temperatures of 300 degrees Fahrenheit or more. The heated water then ascends toward the surface of the earth where, if geological conditions are suitable for its commercial extraction, it can be extracted by drilling geothermal wells. 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.


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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.
 
(CHART)
 
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


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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.
 
(CHART)
 
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.


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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.
 
(CHART)
 
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 revolutions per minute (RPM), temperature and pressure in the OEC, a high efficiency turbine, and the fact that there is no contact between the turbine itself and often corrosive geothermal fluids.
 
We use the same elements of our technology in our recovered energy products. The heat source may be exhaust gases from a simple cycle gas turbine, low pressure steam, or medium temperature liquid found in the process 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.


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Our REG technology is depicted in the graphic below.
 
(CHART)
 
Patents
 
We have been granted 80 U.S. patents (and about 16 pending patents) that 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 thirteen years. No single patent on its own is material to our business.
 
The products-related patents cover components such as turbines, heat exchangers, seals and controls. The system patents cover subjects such as waste heat recovery related to gas pipelines compressors, disposal of non-condensable gases present in geothermal fluids, power plants for very high pressure geothermal resources, and use of two-phase fluids as well as processes related to EGS. A number of patents cover 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 at our Desert Peak 2 and Brady power plants in Nevada in cooperation with GeothermEx Inc., and a number of universities and national laboratories, with funding support from the DOE.
 
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


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(sea water and LNG at minus 238 degrees Fahrenheit, respectively) in the regasification process to generate electrical power from unused heat energy.
 
We also continue to conduct research and development to improve our turbines and other power plant equipment.
 
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 mainly 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 geothermal resources will be developed by 2025. In a report issued in April 2010 for the World Geothermal Congress, Ruggero Bertani of Enel Green Power forecasted that by 2015 the worldwide installed capacity will increase by approximately 73% from 10,715 MW in 2010 to 18,500 MW in 2015. The report identifies the U.S., Indonesia, the Philippines, New Zealand and Mexico as the main contributors to the forecasted growth.
 
In a report issued in April 2010, the Geothermal Energy Association identified a total of 188 confirmed and unconfirmed geothermal projects under various phases of consideration or development in 15 U.S. States that have between 5,254 MW and 7,875 MW potential capacity.
 
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, Iowa, Kansas, Maine, Maryland, Massachusetts, Michigan, Minnesota, Missouri, Montana, New Hampshire, Nevada, New Jersey, New Mexico, New York, North Carolina, North Dakota, Ohio, Oklahoma, Oregon, Pennsylvania, Rhode Island, South Dakota, Texas, Utah, Vermont, Virginia, 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.
 
According to the Database of State Incentives for Renewables and Efficiency (DSIRE), 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 in operation are located) and the District of Columbia define geothermal resources as “renewable”.
 
According to DSIRE, seventeen states have enacted RPS and Alternative Portfolio Standards that include some form of combined heat and power and/or waste heat recovery. The seventeen states are: Arizona, Colorado, Connecticut, Hawaii, Maine, Massachusetts, Michigan, Nevada, New York, 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. In California, then Governor Arnold Schwarzenegger signed an Executive Order on September 15, 2009, requiring most retail sellers of electricity to derive at least 33% of retail sales from eligible renewable resources by 2020. On September 23, 2010, the California Air Resources Board adopted unanimously the 33% renewable electricity standard. Nevada’s RPS requires NV Energy to supply at least 15% of the total electricity it sells from eligible renewable energy resources by 2013, which will increase to 25% by 2025. In 2009, 11% of the electricity retail sales in Nevada were from renewable energy sources. Hawaii’s RPS requires each Hawaiian electric utility that sells electricity for consumption in Hawaii to obtain 15% of its net electricity sales from renewable energy sources by


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December 31, 2015, 20% by December 31, 2020 and 40% by 2030. In 2009, Hawaiian Electric Company and its subsidiaries achieved a consolidated RPS of 19%.
 
In 2006, California passed a state climate change law, AB 32. The goal of AB 32 is to reduce greenhouse gas emissions to 1990 levels by the end of 2020. In 2008, the California Air Resources Board approved a Scoping Plan to carry out regulations implementing AB 32. In December 2010, the California Air Resources Board endorsed cap-and-trade regulation to reduce California’s greenhouse gas emissions under AB 32 The cap-and-trade regulation sets a statewide limit on emissions from sources responsible for emitting 80% of California’s greenhouse gases and according to the California Air Resources Board, will help establish a price signal needed to drive long-term investment in cleaner fuels and more efficient use of energy. On January 21, 2011, the California Superior Court in San Francisco issued a tentative decision that would, if finalized, require the California Air Resources Board to enjoin implementation of the Scoping Plan until the California Air Resources Board complies with certain environmental review obligations. Under the tentative decision, the parties were allowed to file objections to the tentative decision. Both parties filed objections on February 8, 2011. It remains unclear whether there could be any delay to the planned 2012 implementation of the cap-and-trade program. On the federal level on January 2, 2011, the first phase of EPA’s Tailoring Rule took effect in almost all jurisdictions, with the notable exception of the state of Texas. The Tailoring Rule sets thresholds for when permitting requirements under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs apply to certain major sources of greenhouse gas emissions .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. We are permitted to claim 30% of certain eligible costs of a new geothermal power plant in the United States as a one-time credit against our federal income taxes. Alternatively, we are permitted to claim a tax credit based on the power produced from a geothermal power plant. These production-based credits, which in 2010 were 2.2 cents per kWh, are adjusted annually for inflation and may be claimed for ten years on the electricity produced by a new geothermal power plant put into service prior to December 31, 2013. The production-based credits are allowed only to the extent the power is sold to a third party. The owner of the power plant must choose between these two types of tax credits 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 for Specified Energy Projects in Lieu of Tax Credits from the U.S. Treasury. It is available for certain power plants placed in service by the end of 2011, or on which construction begins in 2009, 2010 or 2011 and that are completed by the end of 2013.
 
Whether we claim tax credits or the U.S. Treasury cash grant, we are also permitted to depreciate, or write off, most of the cost of the plant. If we claim the one-time 30% tax credit or receive the U.S. Treasury cash grant, our tax basis in the plant that we can recover through depreciation must be reduced by half of the tax credit or U.S. Treasury cash grant; if we claim other tax credits, there is no reduction in the tax basis for depreciation. For projects that are placed into service after September 8, 2010 and before January 1, 2012, a depreciation “bonus” will permit us to write off 100% of the cost of certain equipment that is part of the geothermal power plant in the year the plant goes into service, if certain requirements are met. For projects that are placed into service after December 31, 2011 and before January 1, 2013, a similar “bonus” will permit us to write off 50% of the cost of that equipment in the year the power plant is placed into service. After applying any depreciation bonus that is available, we can write off the


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remainder of our tax basis in the plant, if any, over five years on an accelerated basis, meaning that more of the cost may be deducted in the first few years than during the remainder of the depreciation period.
 
Collectively, these benefits (to the extent fully utilized) have a present value equivalent to approximately 30% to 40% of the capital cost of a new power plant.
 
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 commence construction on or before September 30, 2011, 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. In December 2010, the United Nations Climate Change Conference was held in Cancún, Mexico. The conference encompassed the 16th Conference of the Parties to the United Nations Framework Convention on Climate Change and the sixth Meeting of the Parties to the Kyoto Protocol. At the conference, the participating countries signed an accord to reduce global warming. While the Cancún agreement is not legally binding, it creates a balanced package of decisions that is designed to set all participating governments more firmly on the path towards a low-emissions future and to support enhanced action on climate change in the developing world. The next Conference of the Parties is scheduled to take place in South Africa in November 2011.
 
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 for 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 committed at the United Nations Climate Change Conference 2009 in Copenhagen to reduce its CO2 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


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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 may 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 built over 20 power plants which generate electricity from “waste heat” from gas turbine-driven compressor stations along interstate natural gas pipelines, from midstream gas processing facilities, and from processing industries in general.
 
Several states, and to a certain extent, the federal government, have recognized the environmental benefits of recovered energy-based power generation. For example, Colorado, Connecticut, Hawaii, Louisiana, Massachusetts, Michigan, 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 their mandatory or voluntary 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 Europe and other markets worldwide may offer similar opportunities in recovered energy-based power generation. In North America, 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 and pricing 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


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  whose activities are dependent on external credit and financing sources that may be subject to availability constraints depending on prevailing global credit and market conditions.
 
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 five 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 80 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.


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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 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, we entered into two joint ventures with Sunday Energy in Israel, one for ground-mounted Solar PV energy systems in which we own 70%, and the other for roof-top Solar PV energy systems in which we own 51%. 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.


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Recent Developments
 
  •  In February 2011, we completed the sale of our part ownership interest in OPC to JPM Capital Corporation for $24.9 million in cash in a transaction to monetize production tax credits. See further details in Item 7 — “Management Discussion and Analysis of Financial Condition and Results of Operations” below under the heading “OPC Transaction”.
 
  •  In February 2011, we signed a PPA with HELCO to sell to the Hawaii Island grid an additional 8 MW of dispatchable geothermal power to be generated from the Puna power plant, at a fixed price (subject to escalation) independent of oil prices. The 20-year PPA is subject to approval by the Public Utilities Commission of Hawaii, with input from the Hawaii Division of Consumer Advocacy. The construction of the power plant has been substantially completed and the power plant is expected to reach full commercial operation after HELCO completes electric grid modifications by the third quarter of 2011.
 
  •  In February 2011, we concluded the issuance of Senior Unsecured Bonds in an aggregate amount of approximately $250 million. The Senior Unsecured Bonds were issued in two tranches. On August 3, 2010, we entered into a trust instrument governing the issuance of, and accepted subscriptions for, an aggregate principal amount of approximately $142.0 million of Senior Unsecured Bonds, and in February 2011 we entered into addendums to the trust instrument governing the issuance of, and accepted subscriptions for, an additional $88 million in aggregate principal amount of Senior Unsecured Bonds (the Additional Bonds). Subject to early redemption, the principal of the Senior Unsecured Bonds is repayable in a single bullet payment upon the final maturity of the Senior Unsecured Bonds on August 1, 2017. The senior unsecured Bonds bear interest at a fixed rate of 7% per annum, payable semi-annually. The Additional Bonds were issued at a premium which reflects an effective fixed interest of 6.75% per annum.
 
  •  Since the beginning of 2010, we have entered into new lease agreements covering approximately 65,000 acres of Federal or private land in Nevada, Utah, Hawaii, Oregon, and California.
 
  •  In November 2010, we closed a $20.0 million term loan with a group of institutional investors, which matures on November 16, 2016, is payable in ten semi-annual installments commencing May 16, 2012, and bears annual interest at a fixed rate of 5.75%.
 
  •  In November 2010, our subsidiary, 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 22 MW of roof top installation. This is the second joint venture agreement between the parties. The first agreement was signed in October 2009. Pursuant to the November 2010 agreement, Sunday Energy will contribute the rights to all of its property required to develop the Solar PV energy systems to SPEs, and Ormat Systems will own 51% of each SPE. The electricity generated from the projects will be sold to Israel Electric Corporation Ltd. under 20-year PPAs.
 
  •  On October 29, 2010, we and NGP agreed to jointly develop, construct, own and operate one or more geothermal power plants in the Crump Geyser Area located in Lake County, Oregon. See additional information under “Projects under Exploration and Development and Future Projects”.
 
  •  In October 2010, we invested $2.0 million in W&M, an early stage company. W&M is engaged in the development of energy harvesting and system balancing solutions for electrical sources, in particular, Solar PV systems. We now hold approximately 28.6% of W&M’s outstanding ordinary shares.
 
  •  We are part of a consortium that consists of international and Israeli organizations (including a university), which in October 2010, won an Israeli governmental tender for the establishment and management of a Technology Center for Renewable Energies (the Center). The Center will be established in the Arava area in Israel. We hold 5.2% of the Center’s shares and are responsible for 4% of the total investment of $11.0 million to be invested over five years.
 
  •  In September 2010, we received from the U.S. Treasury $108.3 million in a cash grant for Specified Energy Property in Lieu of Tax Credits relating to our North Brawley geothermal power plant under Section 1603 of the ARRA.


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  •  On August 25, 2010, we declared commercial operation of the 5.5 MW OREG 3 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 Martin County, Minnesota. The electricity produced by the power plant is sold under a 20-year PPA to Great River Energy.
 
  •  On August 2, 2010, we acquired the remaining 50% interest (14.5 MW) in Mammoth Pacific, an entity that owns the Mammoth complex, for a purchase price of $72.5 million in cash. Following the acquisition, we became the sole owner of the Mammoth complex, and have the rights to over 10,000 acres of undeveloped Federal lands which will enable us to expand the facility and substantially increase its generation capacity.
 
Following the acquisition, Mammoth Pacific, which had been previously accounted for under the equity method, has been included in our consolidated financial statements effective August 2, 2010. The acquisition-date fair value of the initial 50% equity interest was $64.9 million. We recognized in the year ended December 31, 2010, a pre-tax gain of $36.9 million, which is equal to the difference between the acquisition-date fair value of the initial 50% equity interest in Mammoth Pacific and the acquisition-date carrying value of such investment.
 
  •  In July 2010, our subsidiary, Ormat Nevada, engaged John Hancock to arrange senior secured construction and term loan facilities under a DOE loan guarantee program of up to $350 million for three geothermal projects in Nevada. The three projects are the Jersey Valley, McGinness Hills, and Tuscarora geothermal projects. Jersey Valley recently reached completion and is currently at start-up phase, and we have already commenced construction of the other two projects. All three projects are expected to reach commercial operation between 2011 and 2013. John Hancock and the DOE are conducting a due diligence review of the three projects. Upon the satisfactory completion of the review, John Hancock and the DOE will consider issuing a conditional commitment which will lead to a loan guarantee, although we have no guarantee this will occur.
 
  •  On June 3, 2010, Alaska Governor Sean Parnell signed the fiscal year 2011 capital budget including $25 million appropriated to the third round of the Renewable Energy Grant Fund, administrated by the Alaska Energy Authority (AEA). AEA’s recommendations for that round included appropriating $2.0 million to support our exploration and drilling work at Mount Spurr, matched by $2.1 million of Ormat funding. The grant will reimburse us for eligible costs as from July 1, 2010. In the summer of 2010, we performed multiple pre-drilling exploration surveys and in September 2010 drilled two core holes. We plan to continue exploration activities in 2011. The goal for the Renewable Energy Grant Fund is to promote renewable energy projects throughout the State, with a focus on rural Alaska where current diesel-based power prices are very high. The State of Alaska has appropriated a total of $250 million for this program, which funds are expected to be distributed over five years.
 
  •  On June 2, 2010, Alaska Governor Sean Parnell signed Alaska Senate Bill 243. This bill significantly reduces the annual royalty rate paid from geothermal production on State lands from a minimum of 10% of gross revenues to the same level paid on Federal land. Following the passage of Alaska Senate Bill 243, we announced that we will accelerate geothermal exploration work on our Mount Spurr lease.
 
  •  On April 26, 2010, the Medco-Ormat-Itochu-Kyushu Consortium, which consists of Medco Energi Internasional Tbk, Ormat International Inc., our wholly owned subsidiary, Itochu Corporation and Kyushu Electric Power Co. Inc., signed the “Sarulla Project Joint Confirmation” with the state-owned Indonesian power company PLN confirming an agreement on terms for amending the ESC. The ESC had been executed in December 2007 for the 330 MW net power Sarulla Geothermal Project. The Sarulla Project Joint Confirmation was signed during the opening ceremony of the World Geothermal Congress in Bali.
 
The parties agreed to change the price of the power sold under the ESC, such that the tariff payable is higher in the early years after the commercial operation date and reduces in the later years, resulting in a levelized payment of 6.79 cents per kWh. The 90-day schedule for resolving certain other contractual amendments for facilitation of project financing and for signing the resulting amended ESC has expired and negotiations are still ongoing. The modified tariff was verified by the BPKP (Indonesian State Audit Agency for Development) and is now in the process of approval by the Minister of Energy and Mineral Resources.


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Operations of our Electricity Segment
 
How We Own Our Power Plants.  We customarily establish a separate subsidiary to own interests in each power plant. Our purpose in establishing a separate subsidiary for each plant is to ensure that the plant, and the revenues generated by it, will be the only source for repaying indebtedness, if any, incurred to finance the construction or the acquisition (or to refinance the 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 usually 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).


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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 rights 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


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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.


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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 each of the years ended December 31, 2010, and 2009 two sites moved to construction, and during the year ended December 31, 2008 only one site moved to construction. For 2010, these sites were CD4 at the Mammoth complex and DH Wells. For 2009, these sites were Carson Lake and McGinness Hills. For 2008, the one site was Jersey Valley. During the years ended December 31, 2010 and 2009, we discontinued exploration activities at one site each year and during the year ended December 31, 2008 we discontinued exploration activities at two sites. After conducting exploratory drilling, we concluded that the geothermal resource at those sites would not support commercially viable power plants at this time. Those sites were Gabbs, Rock Hills, Buffalo Valley and Grass Valley, all in Nevada. The costs associated with exploration activities at those sites were expensed during the years ended December 31, 2010, 2009, and 2008, respectively (see “Write-off of Unsuccessful Exploration Activities” under Item 7 — “Management Discussion and Analysis of Financial Condition and Results of Operations”). Seven new sites were added to our exploration and development activities in the year ended December 31, 2010, compared with six sites that were added to our exploration activities in the year ended December 31, 2009.
 
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


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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.
 
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.


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Description of Our Leases and Lands
 
We have domestic leases on approximately 444,000 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:
 
  •  79% are leases with the U.S. government, acting through the BLM;
 
  •  8% are leases with various states, none of which is currently material; and
 
  •  13% 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 5,900 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


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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


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


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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).

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Technology   The Heber 1 plant utilizes dual flash and the Heber 2, Heber South, G-1 and G-2 plants utilize binary systems. The complex uses a water cooled system.
     
Subsurface Improvements   30 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 324 degrees Fahrenheit.
     
    Heber production is from deltaic sedimentary sandstones deposited in the subsiding Salton Trough of California’s Imperial Valley. Produced fluids rise from near the magmatic heated basement rocks (~18,000 feet) via fault/fracture zones to the near surface. Heber 1 wells produce directly from deep (4,000 to 8,000 feet) fracture zones. Heber 2 wells produce from the nearer surface (2,000 to 4,000 feet) matrix permeability sandstones in the horizontal outflow plume fed by the fractures from below and the surrounding ground waters.
     
    Scale deposition in the flashing Heber 1 producers is controlled by down hole chemical inhibition supplemented with occasional mechanical cleanouts and acid treatments. There is no scale deposition in the Heber 2 production wells.
     
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.

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Jersey Valley Project    
     
Location   Pershing County, Nevada.
     
Generating Capacity   15 MW.
     
Number of Power Plants   1
     
Technology   The Jersey Valley power plant utilizes an air cooled binary system.
     
Subsurface Improvements   2 production wells and 4 injection wells connected to the plants through a gathering system. The third production well is currently being drilled.
     
Material Equipment   2 OEC units together with the Balance of Plant Equipment.
     
Age   Construction of the power plant was completed at the end of 2010 and it is currently at start-up phase
     
Land and Mineral Rights   The Jersey Valley area is comprised of BLM leases. The leases are held by production. The scheduled expiration dates for all of these leases are after the end of the expected useful life of the power plants.
     
    The power 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”.
     
Resource Information   The expected average temperature of the resource is 330 degrees Fahrenheit.
     
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 from January 1, 2012, assuming the plant will reach COD during the 2011.
     
Financing   Corporate funds.
     
    We engaged John Hancock to arrange senior secured loan facilities under a DOE loan guarantee program of up to $350 million for three geothermal projects, including Jersey Valley.
     
Supplemental Information   The power plant is currently operating at a generating capacity level of 7 MW. We expect COD during the second quarter 2011.
     
Mammoth Complex    
     
Location   Mammoth Lakes, California.
     
Generating Capacity   29 MW.
     
Number of Power Plants   3 (G-1, G-2, and G-3).
     
Technology   The Mammoth complex utilizes air cooled binary systems.
     
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.

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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”.
     
    We recently purchased land at Mammoth that was owned by a third party. This purchase will reduce royalty expenses for the Mammoth complex.
     
Access to Property   Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases.
     
Resource Information   The average resource temperature is 339 degrees Fahrenheit.
     
    The Casa Diablo/Basalt Canyon geothermal field at Mammoth lies on the southwest edge of the resurgent dome within the Long Valley Caldera. It is believed that the present heat source for the geothermal system is an active magma body underlying the Mammoth Mountain to the northwest of the field. Geothermal waters heated by the magma flow from a deep source (> 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   50% — OFC Senior Secured Notes and 50% — corporate funds.
     
Supplemental Information   On August 2, 2010, we acquired the remaining 50% interest in Mammoth Pacific for a purchase price of $72.5 million in cash. Following the acquisition, we became the sole owner of the Mammoth complex.
     
    We plan to repower the Mammoth complex by replacing part of the old units with new Ormat-manufactured equipment. The replacement of the equipment will optimize generation and add approximately 3 MW of generating capacity to the complex.
     
North Brawley Power Plant    
     
Location   Imperial County, California.
     
Generating Capacity   50 MW (See supplemental information below).
     
Number of Power Plants   1
     
Technology   The North Brawley power plant utilizes an air cooled binary system.
     
Subsurface Improvements   16 production wells and 20 injection wells are currently connected to the plant through a gathering system.
     
Material Equipment   5 OEC units together with the Balance of Plant Equipment.

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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 average resource temperature is 335 degrees Fahrenheit.
     
Sources of Makeup Water   Water is provided by IID.
     
Power Purchaser   Southern California Edison.
     
Power Contract Expiration Date   20 years from COD under the PPA.
     
Financing   Corporate funds and cash grant from the U.S. Treasury.
     
Supplemental Information   We faced several challenges during the lengthy startup process. On January 15, 2010, the power plant was placed in service with a stable generation level of 17 MW. We addressed the large quantities of solids in the reservoir by installing solids removal equipment.
     
    We recently commissioned four new injection wells to open up a new injection area east of the existing field. The East Brawley injection wells added more injection capacity. As a result, the generating capacity of the power plant is approximately 30 MW.
     
    There is ongoing work to complete more production wells and increase the output from the facility. However, based on two months of operation data from the East Brawley injection wells, we believe that we may need more injection wells to reach 50 MW.
     
    While we believe that the power plant’s reservoir has sufficient flow to support the originally designed generation capacity of 50 MW, the re-injection of the geothermal fluid has been a challenge.

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    We approached Southern California Edison and requested an extension of the firm operation date (March 31, 2011).
     
    In 2010, the operating costs of the project exceeded revenues; the principal driver for the high operating costs is related to the well field, and is mainly associated with the filtration and production pumps. As previously described, we have reduced the cost of filtration and are taking the necessary steps to substantially reduce production pump costs as well. However, in the first half of 2011, the power plant operating costs are expected to remain high, and a positive EBITDA is expected only towards the end of 2011.
     
    As described above, we have transferred the use of the East Brawley wells to the North Brawley power plant as part of our ongoing efforts to increase the North Brawley power plant generation. In addition, the permitting issue in the East Brawley area is not resolved yet. As a result we decided, at this point of time, not to proceed with the development of the East Brawley project.
     
    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. To date the study has been delayed due to extensive analysis by the Utility.
     
OREG 1 Power Plant    
     
Location   Four Gas compressor stations along natural gas pipeline the Northern Border in North and South Dakota.
     
Generating Capacity   22 MW.
     
Number of Units   4
     
Technology   The OREG 1 power plant utilizes our air cooled OEC 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 air cooled OEC units.

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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.
     
OREG 3 Power plant    
     
Location   A gas compressor station along Northern Border natural gas pipeline in Martin County, Minnesota.
     
Generating Capacity   5.5 MW.
     
Number of Units   1
     
Technology   The OREG 3 power plant utilizes our air cooled OEC units.
     
Material Equipment   One WHOH and one OEC unit along with the Balance of Plant Equipment.
     
Age   The OREG 3 power plant commenced commercial operations during 2010.
     
Land   Easement from NBPL.
     
Access to Property   Direct access to the plant from public roads.
     
Power Purchaser   Great River Energy.
     
Power Contract Expiration Date   2029.
     
Financing   Corporate funds.
     
OREG 4 Power Plant    
     
Location   A Gas compressor station along natural gas pipeline in Denver, Colorado.
     
Generating Capacity   3.5 MW.
     
Number of Units   1
     
Technology   The OREG 4 power plant utilizes our air cooled OEC units.
     
Material Equipment   2 WHOH and 1 OEC unit together with the Balance of Plant Equipment.
     
Age   The OREG 4 power plant commenced commercial operations during 2009.
     
Land   Easement from Trailblazer Pipeline Company.
     
Access to Property   Direct access to the plant from public roads.
     
Power Purchaser   Highline Electric Association.

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Power Contract Expiration Date   2029.
     
Financing   Corporate funds.
     
Ormesa Complex    
     
Location   East Mesa, Imperial County, California.
     
Generating Capacity   54 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 51 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 306 degrees Fahrenheit.
     
    Production is from sandstones. Productive sandstones are between 1,800 and 6,000 feet, and have only matrix permeability. The currently developed thermal anomaly was created in geologic time by conductive heating and direct outflow from an underlying convective fracture system. Produced fluid salinity ranges from 2,000 ppm to 13,000 ppm, and minor scaling and corrosion potential is chemically inhibited.
     
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
     
Puna Power Plant    

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Location   Puna district, Big Island, Hawaii.
     
Generating Capacity   30 MW.
     
Number of Power Plants   1
     
Technology   The Puna plant utilizes our geothermal combined cycle system. The plant uses an air cooled system.
     
Subsurface Improvements   5 production wells and 4 injection wells connected to the plants through a gathering system.
     
Material Equipment   10 OEC units consisting of 10 binary turbines, 10 steam turbines and two bottoming units 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 a private lease. 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   3 PPAs with HELCO (see “Supplemental Information” below).
     
Power Contract Expiration Date   December 31, 2027.
     
Financing   Operating Lease
     
Supplemental Information   The construction of the new 8 MW power plant is substantially completed, but HELCO still needs to complete the modification to the grid for the full benefits of the power plant to be realized, which is expected in the third quarter of 2011.
     
    Recently, we signed a new PPA with HELCO that is still subject to the approval of the Public Utilities Commission of Hawaii, under which the Puna power plant will deliver to the HELCO grid an additional 8 MW at fixed prices (subject to escalation).

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    We have also fixed the energy rate of the 5 MW PPA.
     
Steamboat Complex    
     
Location   Steamboat, Washoe County, Nevada.
     
Generating Capacity   89 MW.
     
Number of Power Plants   7 (Steamboat 1A, Steamboat 2&3, Burdette (Galena 1), Steamboat Hills, Galena 2 and Galena 3).
     
Technology   The Steamboat complex utilizes a binary system (except for Steamboat Hills, which utilizes a single flash system). The complex uses air and water cooling systems.
     
Subsurface Improvements   23 production wells and 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 298 degrees Fahrenheit.
     
    The Steamboat geothermal field is a typical Basin and Range geothermal reservoir. Large and deep faults that occur in the rocks allow circulation of ground water to depths exceeding 10,000 feet below the surface. Horizontal zones of permeability permit the hot water to flow eastward in an out-flow plume.
     
    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.

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Access to Property   Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases.
     
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   OFC Senior Secured Notes (Steamboat 1A, Steamboat 2/3, and Burdette) and OPC Transaction (Steamboat Hills, Galena 2, and Galena 3).
 
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   The Amatitlan power plant utilizes an air cooled binary system and a small back pressure steam turbine (1MW).
     
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.

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Access to Property   Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the 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 CO2 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   The Momotombo power plant utilizes single flash and binary systems. The plant uses air and water cooled 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 466.5 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.

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Power Contract Expiration Date   2014.
     
Financing   A loan from Bank Hapoalim B.M, which was repaid in full in 2010.
     
Olkaria III Complex (Kenya)    
     
Location   Naivasha, Kenya.
     
Generating Capacity   48 MW.
     
Number of Power Plants   2 (Olkaria III Phase 1 and Olkaria III Phase 2).
     
Technology   The Olkaria III complex utilizes an air cooled binary system.
     
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 220 kV sub-station within the power plant, before the transmission lines which belong to the utility.
     
Resource Information   The resource temperature is an average of 570 degrees Fahrenheit.
     
    The Olkaria III geothermal field is on the west side of the greater Olkaria geothermal area located at approximately 6,890 feet above sea level within the Rift Valley.
     
    Hot geothermal fluids rise up from deep in the northeastern portion of the concession area 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.

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Supplemental Information   We initialed an amendment to the existing PPA with the off-taker, KPLC, to expand the Olkaria III complex by up to 52 MW (from 48 MW to up to 100 MW). 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   The Zunil power plant utilizes an air cooled binary system.
     
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 us.
     
    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 that is scheduled to be repaid in full in November 2011.
     
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 2010, the energy revenues were approximately 25% 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 between 131 MW and 147 MW under construction in California, Nevada, and Hawaii (including the Puna and Mammoth expansions described above).
 
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   The Carson Lake power plant will utilize an air cooled binary system.

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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   The drilling activity will resume upon receipt of an EIS for the project. Commercial operation of the power plant is expected in 2013, provided an EIS is granted in 2011.
     
    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, and the delay in completion of the project.
     
CD4 Project (Mammoth Complex) (U.S.)    
     
Location   Mammoth Lakes, California.
     
Projected Generating Capacity   32-38 MW.
     
Projected Technology   The CD4 power plant will utilize an air cooled binary system.
     
Subsurface Improvements   One production well is completed and drilling of another well has started.
     
Land and Mineral Rights   The total Mammoth area is comprised mainly of BLM leases, several of which are held by production and the remainders are the subject of a unitization agreement that is pending BLM approval. The expiration date of the leases (assuming approval of the unitization agreement) is after the end of the expected useful life of the power plant.
     
Access to Property   Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases.
     
Resource Information   The expected average temperature of the resource cannot be estimated as field development has not been completed yet.
     
Power Purchaser   NA.
     
Financing   Corporate funds.

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Supplemental Information   We are participating in the Southern California Edison Wholesale Distribution Access Tariff Transition Cluster Large Generator Interconnection Process to deliver energy into the Southern California Edison system at the Casa Diablo Substation.
     
DH Wells    
     
Location   Mineral County, Nevada.
     
Projected Generating Capacity   20-30 MW.
     
Projected Technology   The DH Wells power plant will utilize a binary system.
     
Material Equipment   Drilling equipment for wells.
     
Condition   We completed the drilling of the first well and are continuing with the drilling activity.
     
Land and Mineral Rights   The DH Wells 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.
     
Financing   Corporate funds.
     
McGinness Hills Project (U.S.)    
     
Location   Lander County, Nevada.
     
Projected Generating Capacity   30 MW.
     
Projected Technology   The McGinness Hills power plant will utilize an air cooled binary system.
     
Subsurface Improvements   4 production wells and 3 injection wells were drilled.
     
Material Equipment   Drilling equipment for wells.
     
Condition   Permits to drill have been obtained. Drilling of additional wells is continuing. We have submitted documents to obtain the required construction permits and an Environmental Assessment is in process. We are in an advanced stage of equipment manufacturing.
     
Land and Mineral Rights   The McGinness Hills area is comprised of private and BLM leases.
     
    The leases are currently held by the payment of annual rental payments, as described in “Description of Our Leases and Lands”.

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    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 COD.
     
Financing   Corporate funds.
     
    We engaged John Hancock to arrange senior secured construction and term loan facilities under a DOE loan guarantee program of up to $350 million for three geothermal projects, including McGinness Hills.
     
Supplemental Information   Commercial operation of the power plant is expected in 2012.
     
Tuscarora Project (U.S.)    
     
Location   Elko County, Nevada.
     
Projected Generating Capacity   18 MW (Phase I).
     
Projected Technology   The Tuscarora power plant will utilize a water cooling binary system.
     
Subsurface Improvements   Three production and four injection wells completed.
     
Condition   Field development is completed. Power plant equipment is on its way to the site. We have submitted documents to obtain the required construction permits.
     
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 COD.
     
Financing   Corporate funds.

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    We engaged John Hancock to arrange senior secured construction and term loan facilities under a DOE loan guarantee program of up to $350 million for three geothermal projects, including Tuscarora.
     
Supplemental Information   Commercial operation of the power plant is expected in 2012.
     
    The project was acquired in February 2010.
     
    Under the PPA, Nevada Power Company 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 of 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, our share in their combined generating capacity would be approximately 160 MW.
 
Crump Geyser Project (U.S.)
 
In October 2010, we and NGP agreed to jointly develop, construct, own and operate one or more geothermal power plants in the Crump Geyser Area located in Lake County, Oregon. All activities will be carried out through CGC, a limited liability company that is owned equally by our wholly owned subsidiary, Ormat Nevada, and NGP.
 
We will be the EPC contractor for the project, which will utilize our proprietary generating equipment and other Balance of Plant Equipment. We will also be the Operator and provide operating and maintenance services to CGC.
 
We and NGP intend to build an up to 30 MW power plant, which is expected to be placed in service before the end of 2013 in order to qualify for the U.S. Treasury cash grant for Specified Energy Property in Lieu of Tax Credits under Section 1603 of the ARRA. We have recently completed the drilling of an injection well and we plan to continue with the drilling activity throughout 2011.
 
Olkaria III Phase 3 (Kenya)
 
We are currently developing Phase 3 of the Olkaria III complex located in Naivasha, Kenya. We initialed an amendment to the existing PPA with the off-taker, KPLC, to expand the Olkaria III complex by up to 52 MW (from 48 MW to up to 100 MW).We expect to sign a formal amendment to the PPA upon receipt of regulatory approval and the consent of the lenders that provided the financing or the existing power plant.
 
The expansion is to be developed in two phases. Phase I will be comprised of 36 MW within up to three years from finalizing the amendment to the existing PPA. An optional phase II may be comprised of up to 16 MW within up to eight years from finalizing the amendment to the existing PPA.
 
Solar PV Projects (Israel)
 
We are currently in the process of developing ground-mounted and roof-top Solar PV projects in Israel together with Sunday Energy under two joint venture agreements. Under the ground-mounted joint venture agreement, we plan to build six projects with a total capacity of 38 MW. Our share in these projects will be 70%. Under the roof-top joint venture agreement, we plan to build eight projects with a total capacity of 18 MW. Our share in these projects will be 51%.
 
We have completed feasibility studies for most of these projects as required by the Israel Electric Corporation Ltd and we have submitted applications to obtain conditional licenses for these projects from the PUA. We believe

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that the installation permitting process for the ground-mounted projects will take longer to complete because of the zoning changes required for the land, compared to the permitting process for the roof-top projects, which do not require zoning changes.
 
In addition to the projects mentioned above, we are developing and are in the permitting phase for a roof-top solar PV installation on our manufacturing facility in Yavne.
 
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 330 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 adjustment of the electricity tariff for the 330 MW Sarulla project has been agreed between PLN (the state electric utility which is the off-taker of the electricity from the Sarulla Project) and the consortium based on the verification of the agreed tariff by the BPKP (Indonesian State Auditor for Development). The agreed adjusted tariff is now in the process of approval by the Ministry of Energy and Mineral Resources, which is anticipated during the first half of 2011.
 
Sarulla Operations Ltd. (the project company) has received responses from over ten international banks that were invited to submit proposals to provide limited recourse financing for the Sarulla Project. The expected financing package will consist of direct loans from the Japan Bank for International Cooperation (JBIC) and the Asian Development Bank (ADB), plus Extended Political Risk Guarantees to the participating banks by JBIC. Sarulla Operations Ltd. has shortlisted the candidates and is currently in the process of selecting the mandated lead arrangers (MLAs) out of those shortlisted candidates.
 
From past experience it is hard to estimate when these negotiations will be concluded. Construction is expected to start after the consortium obtains financing, a process which we expect to take approximately one year from completion of the ESC negotiations with PLN.
 
Wister Project (U.S.)
 
We are currently developing the Wister project on private leases located in Imperial County, California. During 2010, we increased our land position in the project area and are currently progressing with exploration activity. We expect the first phase of the project to be 30 MW. Commercial operation of the first phase is scheduled for the end of 2013.
 
The project has been awarded an exploration grant of $4.5 million under the DOE’s Innovative Exploration and Drilling Projects program and the exploration activity under this program has started.


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In addition to the geothermal projects listed above, we have various leases for geothermal resources, in some of 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, Idaho, Oregon, and Utah in the U.S., and in Guatemala and Chile. These leases are comprised of approximately 343,000 acres, including the following:
 
     
 
Nevada
   
Beowawe
  Lease acquired but no further action has yet been taken.
Dixie Hope
  Completed exploration studies and are awaiting permits to start exploratory drilling at the site.
Dixie Meadows
  Started exploration studies.
Edwards Creek
  Completed exploration studies and are awaiting permits to start 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
  Under exploration studies.
Tungsten Mountain
  Completed exploration studies and are awaiting permits to start exploratory drilling at the site.
Tuscarora Expansion
  Lease acquired but no further action has yet been taken.
Walker River
  We have an option to start exploration studies.
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.
Rhyolite Plateau
  Lease acquired but no further action has yet been taken.
Hawaii
   
Ulupalakua (Maui)
  Advanced exploration studies and the project has been awarded an exploration grant of $4.9 million under the DOE’s Innovative Exploration and Drilling Projects program.
Kula
  Lease acquired but no further action has yet been taken.
Oregon
   
Glass Buttes — Mahogany
  Completed exploration studies and the project has been awarded an exploration grant of $4.3 million under the DOE’s Innovative Exploration and Drilling Projects program. Awaiting permits to start exploratory drilling.
Glass Buttes — Midnight Point
  Completed exploration studies.
Newberry
  Started exploration studies.
Idaho
   
Magic Reservoir
  Lease acquired but no further action has yet been taken.
Alaska
   
Mount Spurr
  Started exploration drilling at the site and a $2.0 million exploration grant has been awarded.
Utah
   
Drum Mountain
  Under exploration studies.
Whirlwind Valley
  Under exploration studies.


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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 5,590 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.
 
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

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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 $51.0 million as of February 15 2011, which includes revenues for the period between January 1, 2011 and February 15, 2011, compared to $90.0 million as of February 28, 2010. The following is a breakdown of the Product Segment backlog:
                             
        Sales
             
    Expected
  Expected to
             
    Completion
  be Recognized
             
    of the Contract   in 2011              
        (In millions)              
 
Geothermal
  2011   $ 24.2                  
Recovered Energy
  2011     12.1                  
Remote Power Units
  2011     12.1                  
Other
  2011     2.5                  
                             
Total Product Backlog
      $ 51.0                  
                             
 
The backlog includes $30 million that will be effective upon receipt of letters of credit, and excludes $15 million of revenues related to a REG plant specifically designed to use the residual energy from the vaporization process at LNG regasification terminal in Spain that we expect to recognize in the first half of 2011, subject to acceptance by 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., NGP, Raser Technologies Inc., Magma Energy Inc., Ram Power Corp., and Gradient Resource. 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.


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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 a Pratt & Whitney Power Systems company, 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 economic 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, 2010 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), HELCO, and SCPPA accounted for 29.1%, 15.0%, 8.6% and 2.5% of revenues, respectively, for the year ended December 31, 2010. Based on publicly available information, as of December 31, 2010, the issuer ratings of Southern California Edison, HELCO, Sierra Pacific Power Company, Nevada Power Company, and SCPPA were as set forth below:
 
         
Issuer   Standard & Poor’s Ratings Services   Moody’s Investors Service Inc.
 
Southern California Edison
  BBB+ (stable outlook)   A3 (stable outlook)
HELCO
  BBB- (stable outlook)   Ratings Withdrawn
Sierra Pacific Power Company
  BB (stable outlook)   Ba2 (stable outlook)
Nevada Power Company
  BB (stable outlook)   Ba2 (stable outlook)
SCPPA
  BBB (Outlook Developing)   Aa3 (stable outlook)
 
The credit ratings of any power purchaser may change from time to time. There is no publicly available information with respect to the credit rating or stability of the power purchasers under the PPAs for our foreign power plants.
 
Our revenues from the product 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, 2010, Las Pailas accounted for more than 26.2% of our product segment revenues and 5.7% of our total revenues.


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Raw Materials, Suppliers and Subcontractors
 
In connection with our manufacturing activities, we use raw materials such as steel and aluminum. We do not rely on any one supplier for the raw materials used in our manufacturing activities, as all of such raw materials are readily available from various suppliers.
 
We use subcontractors for some of the manufacturing for our products components and for construction activities of our power plants, which 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, 2010, we employed 1,146 employees, of, which 499 were located in the United States, 493 were located in Israel and 154 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, volcanic eruption and earthquake coverage, and primary and excess liability insurance, as well as customary worker’s compensation and automobile insurance and such other insurance, if any, as is generally carried by companies engaged in similar businesses and owning similar properties in the same general areas or as may be required by any lease, financing arrangement, or other contract. To the extent any such casualty insurance covers both us and/or our power plants, and any other person and/or plants, we generally have specifically designated as applicable solely to us and our power plants “all risk” property insurance coverage in an amount based upon the estimated full replacement value of our power plants (provided that earthquake, volcanic eruption and flood coverage may be subject to annual aggregate limits depending on the type and location of the power plant) and business interruption insurance in an amount that also varies from power plant to power plant.
 
We generally purchase insurance policies to cover our exposure to certain political risks involved in operating in developing countries. Political risk insurance policies are generally issued by entities which specialize in such policies, such as the Multilateral Investment Guarantee Agency (a member of the World Bank Group), and from private sector providers, such as Zurich Emerging Markets and other such companies. To date all of our political risk insurance contracts are with the Multilateral Investment Guarantee Agency and with Zurich Emerging Markets. We have obtained such insurance for all of our foreign power plants currently in operation. However, the policy for the Amatitlan Geothermal Project in Guatemala was terminated following the financing of the project in 2009 due to our reduced equity exposure. Such insurance policies generally cover, subject to the limitations and restrictions contained therein, approximately 90% of our losses derived from a specified governmental act, such as confiscation,


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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


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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


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loss of any such status would result in the occurrence of an event of default under the indenture for the OFC Senior Secured Notes and the OrCal Senior Secured Notes and hence would give the indenture trustee the right to exercise remedies pursuant to the indenture and the other financing documents.
 
State Regulation
 
Our power plants in California and Nevada, by virtue of being Qualifying Facilities that make only wholesale sales of electricity, are not subject to rate, financial and organizational regulations applicable to electric utilities in those states. The power plants each sell or will sell their electrical output under PPAs to electric utilities (Sierra Pacific Power Company, Nevada Power Company, Southern California Edison or SCPPA). All of the utilities except SCPPA are regulated by their respective state public utilities commissions. Sierra Pacific Power Company and Nevada Power Company are regulated by the PUCN. Southern California Edison is regulated by the CPUC.
 
Under Hawaii law, non-fossil generators are not subject to regulation as public utilities. Hawaii law provides that a geothermal power producer is to negotiate the rate for its output with the public utility purchaser. If such rate cannot be determined by mutual accord, the 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


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that are required, including risk management plans (federal and state programs) and hazardous materials management plans (in California).
 
In some cases our projects may also require permits, issued by the applicable federal agencies or authorized state agencies, regarding threatened or endangered species, permits to impact wetlands or other waters and notices of construction of structures which may have an impact on airspace. Environmental laws and regulations may change in the future, which may lead to increases in the time to receive such permits and associated costs of compliance.
 
As of the date of this report, all of the material environmental permits and approvals currently required for our operating power plants have been obtained. We are currently experiencing regulatory delays in obtaining various environmental permits and approvals required for projects in development and construction. These delays may lead to increases in the time and cost to complete these projects. Our operations are designed and conducted to comply with applicable environmental permit and approval requirements. Non-compliance with any such requirements could result in fines or other penalties.
 
Environmental Laws and Regulations
 
Our facilities are subject to a number of environmental laws and regulations relating to development, construction and operation of geothermal facilities. In the United States, these may include the Clean Air Act, the Clean Water Act, the Emergency Planning and Community Right-to-Know Act, the Endangered Species Act, the National Environmental Policy Act, the Resource Conservation and Recovery Act, and related state laws and regulations.
 
Our operations involve significant quantities of brine (substantially, all of which we reinject into the subsurface) and scale, both of which can contain materials (such as arsenic, lead, and naturally occurring radioactive materials) in concentrations that exceed regulatory limits used to define hazardous waste. We also use various substances, including isopentane and industrial lubricants, that could become potential contaminants and are generally flammable. Hazardous materials are also used in our equipment manufacturing operations in Israel. As a result, our projects are subject to domestic and foreign federal, state and local statutory and regulatory requirements regarding the use, storage, fugitive emissions, and disposal of hazardous substances. The cost of remediation activities associated with a spill or release of such materials could be significant.
 
Although we are not aware of any mismanagement of these materials, including any mismanagement prior to the acquisition of some of our power plants, that has materially impaired any of the power plant sites, any disposal or release of these materials onto the power plant sites, other than by means of permitted injection wells, could lead to contamination of the environment and result in material cleanup requirements or other responsive obligations under applicable environmental laws. We believe that at one time there may have been a gas station located on the Mammoth complex site, but because of significant surface disturbance and construction since that time further physical evaluation of the environmental condition of the former gas station site has been impractical. We believe that, given the subsequent surface disturbance and construction activity in the vicinity of the suspected location of the service station, it is likely that environmental contamination, if any, associated with the former facilities and any associated underground storage tanks would have already been encountered if they still existed.
 
Regulation of the Electric Utility Industry in our Foreign Countries of Operation
 
The following is a summary overview of certain aspects of the electric industry in the foreign countries in which we have an operating geothermal power plant and should not be considered a full statement of the laws in such countries or all of the issues pertaining thereto.
 
Nicaragua.  In 1998, two laws were approved by Nicaraguan authorities, Law No. 272-98 and Law No. 271-98, which define the structure of the energy sector in the country. Law No. 272-98 provides for the establishment of the CNE, which is responsible for setting policies, strategies and objectives as well as approving indicative plans for the energy sector. Law No. 271-98 formally assigned regulatory, supervisory, inspection and oversight functions to the INE.


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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 three 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.


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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       42  
2012
    65       115       40  
2013
    85       200       38  
2014-2017
    100       300       36  
 
 
* Based on an exchange rate of the NIS/dollar as of December 31, 2010 ($1 = NIS 3.549)
 
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 Corporation 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 high voltage 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 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.
 
In December 2010, the National Planning Council of the Israeli Ministry of Interior issued regulations for the development of solar installations in Israel.
 
The regulations include guidelines for the statutory planning route for the development of solar projects on agricultural and nonagricultural land.
 
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 90-day period the developer is supposed to close the


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financing terms. Once the financing terms are finalized, the provisional tariff approval will become permanent; the tariff will be secured for 20 years from commencement of commercial operation, and the developer may 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 78.2% of our total revenues for the year ended December 31, 2010 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 that, in certain respects, are similar to those typically associated with oil and gas exploration, development, and exploitation, such as dry holes, uncontrolled releases, and pressure and temperature decline. Any of these uncertainties may increase our capital expenditures and our operating costs, or


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reduce the efficiency of our power plants. 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, which would adversely affect our development of geothermal 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. 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 and/or reservoir pressure decline in the normal course of operations. For example, some of Brady’s production wells have cooled significantly due to breakthrough from injection wells. At Momotombo, early operations without injection resulted in reservoir pressure decline and consequent reduced productivity and scale plugging in the formation near the producer wellbores. Because geothermal reservoirs are complex geological structures, we can only estimate their geographic area and sustainable output. The viability of geothermal power plants depends on different factors directly related to the geothermal resource (such as the temperature, pressure, storage capacity, transmissivity, and recharge) as well as operational factors relating to the extraction or reinjection of geothermal fluids. At our North Brawley power plant instability of the sands and clay in the geothermal resource and variability in the chemical composition of the geothermal fluid have all combined to increase our capital expenditures for the project, as well as our ongoing operating expenses, and have so far prevented the project from sustainable operation at its intended design capacity. Our geothermal energy power plants may also suffer an unexpected decline in the capacity of their respective geothermal wells and are exposed to a risk of geothermal reservoirs not being sufficient for sustained generation of the electrical power capacity desired over time.
 
Another aspect of geothermal operations is the management and stabilization of subsurface impacts caused by fluid injection pressures of production and injection fluids to mitigate subsidence. In the case of the geothermal resource supplying the Heber complex, pressure drawdown in the center of the well field has caused some localized ground subsidence, while pressure in the peripheral areas has caused localized ground inflation. Inflation and subsidence, if not controlled, can adversely affect farming operations and other infrastructure at or near the land surface. Potential costs, which cannot be estimated and may be significant, of failing to stabilize site pressures in the Heber complex area include repair and modification of gravity-based farm irrigation systems and municipal sewer piping and possible repair or replacement of a local road bridge spanning an irrigation canal.
 
Additionally, active geothermal areas, such as the areas in which our power plants are located, are subject to frequent low-level seismic disturbances. Serious seismic disturbances are possible and could result in damage to our power plants or equipment or degrade the quality of our geothermal resources to such an extent that we could not perform under the PPA for the affected power plant, which in turn could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow. If we suffer a serious seismic disturbance, our business interruption and property damage insurance may not be adequate to cover all losses sustained as a result thereof. In addition, insurance coverage may not continue to be available in the future in amounts adequate to insure against such seismic disturbances.
 
Furthermore, absent additional geologic/hydrologic studies, any increase in power generation from our geothermal power plants, 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.


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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.
 
We rely on power transmission facilities that we do not own or control.
 
We depend on transmission facilities owned and operated by others to deliver the power we sell from our power plants to our customers. If transmission is disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver power to our customers may be adversely impacted and we may either incur additional costs or forego revenues. In addition, lack of access to new transmission capacity may affect our ability to develop new projects. Existing congestion of transmission capacity, as well as expansion of transmission systems and competition from other developers seeking access to expanded systems, could also affect our performance.
 
The aftermath of the recent global recession and its attendant credit constraints could adversely affect us.
 
We may continue to experience lower levels of worldwide demand for energy, and face tighter credit markets, as the world economy continues to recover from the disruption in the global credit markets, failures or material business deterioration of investment banks, commercial banks, and other financial institutions and intermediaries in the United States and elsewhere around the world, and significant reductions in asset values across businesses, households and individuals that led to the recent global recession. These conditions may adversely affect both our Electricity and Product Segments. Among other things, we might face:
 
  •  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;


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  •  potential declines in revenues in our Product Segment due to reduced or postponed orders or other factors caused by economic challenges faced by our customers and prospective customers; and
 
  •  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, 2010, we had approximately $789.7 million of total consolidated indebtedness, of which approximately $361.0 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 $142.9 million for the year ended December 31, 2010, which represented 38.3% 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;


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  •  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) and HELCO have accounted for 29.1%, 15.0% and 8.6%, respectively, of our revenues for the year ended December 31, 2010. 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.


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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 PPAs of our Burdette, Desert Peak 2, Galena 2, Galena 3, Carson Lake, Jersey Valley, McGinness Hills, Tuscarrora and North Brawley projects, 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. Three of these nine projects were in commercial operation in 2010, 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 CPUC. 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.
 
In December 2010, a global settlement (Global Settlement) relating primarily to the purchase and payment obligations of investor-owned utilities to combined heat and power (CHP) Qualifying Facilities was approved by


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the CPUC. The Global Settlement will become effective upon the satisfaction of certain conditions precedent, including (a) a final and non-appealable order from the FERC approving the investor-owned utilities’ request for a waiver of the QF must-take purchase obligation for Qualifying Facilities above 20 MW; and(b) that the CPUC order becomes final and non-appealable. As of February 22, 2011, not all of the conditions precedent (including the two noted above) have been satisfied.
 
Under the terms of the Global Settlement, existing Qualifying Facilities with “Legacy PPAs” (meaning any PPA that is in effect at the time the Global Settlement goes into effect) will have the option to choose to enter into a “Legacy PPA Amendment” within 180 days of the effectiveness of the Global Settlement. The Legacy PPA Amendment will allow a Qualifying Facility to choose a pricing methodology option going forward from the “pricing effective date”, which in Ormat’s case will be the end of the fixed rate period that terminates April 2012 under a prior settlement agreement with Southern California Edison. The pricing options include:
 
(1) switching to a new SRAC methodology, which has fixed, declining heat rates, a variable O&M component, an adjustment based on location, and a price adjustment if greenhouse gas (GHG) costs are imposed on the facility, all until December 31, 2014, after which the SRAC will be tied only to a formula with energy market heat rates;
 
(2) the same formula specified in (1) above but with somewhat higher heat rates and no GHG cost adder;
 
(3) the same formula specified in (1) above but with heat rates between options (1) and (2) and a fixed GHG payment of $20 per metric ton for allowances used by a facility;
 
(4) the same pricing terms as (3) above, but tied to actual GHG costs imposed on a facility, capped at $12.50 per metric ton; or
 
(5) a 90-day negotiation period to see if the parties can turn the PPA into a tolling agreement on agreed terms.
 
If an existing Qualifying Facility chooses not to enter into a Legacy PPA Amendment, its pricing under the existing Legacy PPA will revert at the end of the current fixed rate period (meaning, in Ormat’s case, the one that ends April 2012) to the SRAC formula pricing specified in (1) above.
 
The Global Settlement further provides that after July 1, 2015 if the term of a Qualifying Facility’s Legacy PPA expires, the utility will have no obligation to purchase power from the Qualifying Facility if the Qualifying Facility has a generating capacity in excess of 20 MW. Until July 1, 2015, a transition PPA will be available for Qualifying Facilities with Legacy PPAs that expire, which will incorporate the pricing structure outlined above. The investor-owned utilities have also agreed to conduct competitive solicitations for CHP Qualifying Facilies’ output (akin to the competitive solicitations available to renewable generators under the State’s Renewables Portfolio Standard program, but with various differences). There are also several other contracting options under the Global Settlement, including bilateral contracts with the investor-owned utilities. Qualifying Facilities below 20 MW will be entitled to a new standard offer PPA, with SRAC pricing and capacity payments as determined from time to time by the CPUC. The joint parties to the Global Settlement have agreed that the utilities can go to FERC to obtain a waiver of the mandatory purchase obligation under PURPA for Qualifying Facilities above 20 MW, which is one of the conditions precedent for the Global Settlement.
 
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.


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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


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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


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  •  the difficulty of establishing and maintaining uniform standards, controls, procedures and policies, including accounting controls and procedures.
 
If any of our acquired companies suffers customer dissatisfaction or performance problems, 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 reduction or elimination of government incentives related to solar power could cause the revenues we expect to derive from our solar power joint venture to decline.
 
Today, the cost of solar power exceeds the cost of power furnished by the electric utility grid in most locations. As a result, federal, state and local government bodies in many countries have provided various incentives in the form of rebates, tax credits, mandated feed-in-tariffs and other incentives to end users, distributors, system integrators and manufacturers of solar power products to promote the use of solar energy to reduce dependency on other forms of energy. These government economic incentives could be reduced or eliminated. Reductions in, or eliminations or expirations of, incentives related to solar power could result in decreased demand for solar power and adversely affect the revenues we expect to derive from our solar power joint venture in Israel.
 
We face competition from other companies engaged in the solar energy sector.
 
The solar power market is intensely competitive and rapidly evolving. We compete with many companies that have longer operating histories in this sector, larger customer bases, and greater brand recognition, as well as, in some cases, significantly greater financial and marketing resources than us. In some cases, these competitors are vertically integrated in the solar energy sector, manufacturing Solar PV, silicon wafers, and other related products for the solar industry, which may give them an advantage in developing, constructing, owning and operating solar power projects. We do not represent a significant competitive presence in the solar power market. Our lack of experience in the Solar PV sector may affect our ability to successfully develop, construct, finance, and operate Solar PV power projects.
 
The existence of a prolonged force majeure event or a forced outage affecting a power plant 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


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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, 2010, from the power plants utilizing the IID transmission system, were approximately $110.4 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. 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.


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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, Yoram Bronicki, Nadav Amir, 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,


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


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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.
 
Possible fluctuations in the cost of construction, raw materials, and drilling may materially and adversely affect our business, financial condition, future results, and cash flow.
 
Our manufacturing operations are dependent on the supply of various raw materials, including primarily steel and aluminum, and on the supply of various industrial equipment components that we use. We currently obtain all such materials and equipment at prevailing market prices. We are not dependent on any one supplier and do not have any long-term agreements with any of our suppliers. Future cost increases of such raw materials and equipment, to the extent not otherwise passed along to our customers, could adversely affect our profit margins.
 
Conditions in and around Israel, where the majority of our senior management and all of our production and manufacturing facilities are located, may adversely affect our operations and may limit our ability to produce and sell our products or manage our power plants.
 
Operations in Israel accounted for approximately 18.8%, 29.7%, and 27.7% of our operating expenses in the years ended December 31, 2010, 2009, and 2008, 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.
 
Negotiations between Israel and representatives of the Palestinian Authority in an effort to resolve the state of conflict have been sporadic and have failed to result in peace. The establishment in 2006 of a government in the Gaza territory by representatives of the Hamas militant group has created additional unrest and uncertainty in the region. 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.
 
The recent political instability and civil unrest in the Middle East and North Africa have raised new concerns regarding security in the region and the potential for armed conflict or other hostilities involving Israel. We could be adversely affected by any such hostilities, the interruption or curtailment of trade between Israel and its trading partners, or a significant downturn in the economic or financial condition of Israel. In addition, the sale of products manufactured in Israel may be adversely affected in certain countries by restrictive laws, policies or practices directed toward Israel or companies having operations in Israel.
 
In addition, some of our employees in Israel are subject to being called upon to perform military service in Israel, and their absence may have an adverse effect upon our operations. Generally, unless exempt, male adult citizens of Israel under the age of 41 are obligated to perform up to 36 days of military reserve duty annually. Additionally, all such citizens are subject to being called to active duty at any time under emergency circumstances.
 
These events and conditions could disrupt our operations in Israel, which could materially harm our business, financial condition, future results, and cash flow.


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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, 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.


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We are a holding company and our revenues depend substantially on the performance of our subsidiaries and the power plants they operate, most of which are subject to restrictions and taxation on dividends and distributions.
 
We are a holding company whose primary assets are our ownership of the equity interests in our subsidiaries. We conduct no other business and, as a result, we depend entirely upon our subsidiaries’ earnings and cash flow.
 
The agreements pursuant to which most of our subsidiaries have incurred debt restrict the ability of these subsidiaries to pay dividends, make distributions or otherwise transfer funds to us prior to the satisfaction of other obligations, including the payment of operating expenses, debt service and replenishment or maintenance of cash reserves. In the case of some of our power plants that are owned jointly with other partners there may be certain additional restrictions on dividend distributions pursuant to our agreements with those partners. Further, if we elect to receive distributions of earnings from our foreign operations, we may incur United States taxes on account of such distributions, net of any available foreign tax credits. In all of the foreign countries where our existing power plants are located, dividend payments to us are also subject to withholding taxes. Each of the events described above may reduce or eliminate the aggregate amount of revenues we can receive from our subsidiaries.
 
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 60% of our common stock. Bronicki Investments Ltd. holds approximately 35.1% of the outstanding shares of common stock of Ormat Industries Ltd. as of February 22, 2011 (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 may be highly volatile and may fluctuate substantially due to many factors, including:
 
  •  actual or anticipated fluctuations in our results of operations including as a result of seasonal variations in our electricity-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;


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  •  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 60% of our outstanding common stock and some of our directors, officers and employees also hold shares of our outstanding common stock. Sales of such shares in the public market, as well as shares we may issue upon exercise of outstanding options, could cause the market price of our common stock to decline. On November 10, 2004, we entered into a registration rights agreement with Ormat Industries whereby Ormat Industries may require us to register our common stock held by it or its directors, officers and employees with the SEC or to include our common stock held by it or its directors, officers and employees in an offering and sale by us.
 
Provisions in our charter documents and Delaware law may delay or prevent acquisition of us, which could adversely affect the value of our common stock.
 
Our restated certificate of incorporation and our bylaws contain provisions that could make it harder for a third party to acquire us without the consent of our Board of Directors. These provisions do not permit actions by our stockholders by written consent. In addition, these provisions include procedural requirements relating to stockholder meetings and stockholder proposals that could make stockholder actions more difficult. Our Board of Directors is classified into three classes of directors serving staggered, three-year terms and may be removed only for cause. Any vacancy on the Board of Directors may be filled only by the vote of the majority of directors then in office. Our Board of Directors has the right to issue preferred stock without stockholder approval, which could be used to institute a “poison pill” that would work to dilute the stock ownership of a potential hostile acquirer, effectively preventing acquisitions that have not been approved by our Board of Directors. Delaware law also imposes some restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. Although we believe these provisions provide for an opportunity to receive a higher bid by requiring potential acquirers to negotiate with our Board of Directors, these provisions apply even if the offer may be considered beneficial by some stockholders.
 
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


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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 2010, other than as described below.
 
Securities Class Actions
 
Following the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs, three securities class action lawsuits were filed in the United States District Court for the District of Nevada on March 9, 2010, March 18, 2010 and April 7, 2010. These complaints assert claims against the Company and certain officers and directors for alleged violation of Sections 10(b) and 20(a) of the Exchange Act. One complaint also asserts claims for alleged violations of Sections 11, 12(a)(2) and 15 of the Securities Act. All three complaints allege claims on behalf of a putative class of purchasers of Company stock between May 6, 2008 or May 7, 2008 and February 23, 2010 or February 24, 2010.
 
These three lawsuits were consolidated by the Court in an order issued on June 3, 2010 and the Court appointed three of the Company’s stockholders to serve as lead plaintiffs. Lead plaintiffs filed a consolidated amended class action complaint (CAC) on July 9, 2010 that asserts claims under Sections 10(b) and 20(a) of the Exchange Act on behalf of a putative class of purchasers of Company stock between May 7, 2008 and February 24, 2010. The CAC alleges that certain of the Company’s public statements were false and misleading for failing to account properly for the Company’s exploration and development costs based on the Company’s announcement on February 24, 2010 that it was going to restate its financial results to change its method of accounting for exploration and development costs in certain respects. The CAC also alleges that certain of the Company’s statements concerning the North Brawley project were false and misleading. The CAC seeks compensatory damages, expenses, and such further relief as the Court may deem proper. The Company cannot make an estimate of the possible loss or range of loss.
 
Defendants filed a motion to dismiss the CAC on August 13, 2010 which remains pending.
 
The Company does not believe that these lawsuits have merit and is defending the actions vigorously.


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Stockholder Derivative Cases
 
Four stockholder derivative lawsuits have also been filed in connection with the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs. Two cases were filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe on March 16, 2010 and April 21, 2010 and two in the United States District Court for the District of Nevada on March 29, 2010 and June 7, 2010. All four lawsuits assert claims brought derivatively on behalf of the Company against certain of its officers and directors for alleged breach of fiduciary duty and other claims, including waste of corporate assets and unjust enrichment.
 
The two stockholder derivative cases filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe were consolidated by the Court in an order dated May 27, 2010 and the plaintiffs filed a consolidated derivative complaint on September 7, 2010. In accordance with a stipulation between the parties, defendants filed a motion to dismiss on November 16, 2010 which remains pending. The Company cannot make an estimate of the possible loss or range of loss on the state derivative cases.
 
The two federal derivative cases filed in the United States District Court for the District of Nevada were consolidated by the Court in an order dated August 31, 2010. Plaintiffs filed a consolidated derivative complaint on October 28, 2010 and in accordance with a stipulation by the parties, defendants filed a motion to dismiss on December 13, 2010 which remains pending. The Company cannot make an estimate of the possible loss or range of loss on the federal derivative cases.
 
The Company believes the allegations in these purported derivative actions are also without merit and is defending the actions vigorously.
 
Other
 
In addition, from time to time, we are named as a party to various lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our business. These actions typically seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to such lawsuits, claims and proceedings, we accrue reserves in accordance with U.S. GAAP. 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 and cash flows.


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PART II
 
ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
Our common stock is traded on the NYSE under the symbol “ORA”. Public trading of our stock commenced on November 11, 2004. Prior to that, there was no public market for our stock. As of February 22, 2011, there were 17 record holders of the Company’s common stock. On February 22, 2011, our stock’s closing price as reported on the NYSE was $27.95 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 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
May 5, 2010
  $ 0.05     May 18, 2010   May 25, 2010
August 4, 2010
  $ 0.05     August 17, 2010   August 26, 2010
November 2, 2010
  $ 0.05     November 17, 2010   November 30, 2010
February 22, 2011
  $ 0.05     March 15, 2011   March 24, 2011
 
High/Low Stock Prices:
 
Ormat Technologies, Inc. (ORA) — High and Low Prices for the years ended December 31, 2009 and 2010, and from January 1, 2011 until February 22, 2011:
 
                                                                         
                                    January 1
    First
  Second
  Third
  Fourth
  First
  Second
  Third
  Fourth
  to
    Quarter
  Quarter
  Quarter
  Quarter
  Quarter
  Quarter
  Quarter
  Quarter
  February, 22
    2009   2009   2009   2009   2010   2010   2010   2010   2011
 
High
  $ 35.88     $ 41.77     $ 42.68     $ 44.13     $ 38.00     $ 32.35     $ 29.45     $ 30.08     $ 31.18  
Low:
  $ 22.84     $ 26.85     $ 33.99     $ 35.70     $ 27.68     $ 26.55     $ 26.13     $ 26.8     $ 27.95  


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Stock Performance Graph:
 
The following performance graph represents the cumulative total shareholder return for the period November 11, 2004 (the date upon which trading of the Company’s common stock commenced) through December 31, 2010 for our common stock, compared to the Standard and Poor’s Composite 500 Index, and two peer groups.
 
Comparison of Cumulative Returns for the Period November 11, 2004 through December 31, 2010
 
(PERFORMANCE GRAPH)
 
                                                                                 
      11/11/2004     12/31/2004     12/31/2005     12/31/2006     12/31/2007     12/31/2008     12/31/2009     12/31/2010
Ormat Technologies Inc. 
    $ 100       $ 109       $ 174       $ 245       $ 367       $ 212       $ 252       $ 197  
Standard & Poor’s Composite 500 Index
    $ 100       $ 108       $ 111       $ 126       $ 131       $ 80       $ 99       $ 112  
IPP Peers*
    $ 100       $ 119       $ 110       $ 167       $ 163       $ 131       $ 187       $ 218  
Renewable Peers*
    $ 100       $ 126       $ 202       $ 170       $ 327       $ 102       $ 101       $ 77  
                                                                                 
 
* 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., NGP., 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”.


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ITEM 6.   SELECTED FINANCIAL DATA
 
The following table sets forth our selected consolidated financial data for the years ended and at the dates indicated. We have derived the selected consolidated financial data for the years ended December 31, 2010, 2009 and 2008 and as of December 31, 2010 and 2009 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, 2007 and 2006, and as of December 31, 2008, 2007 and 2006 from our audited consolidated financial statements not included herein.
 
The information set forth below should be read in conjunction with Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements set forth in Item 8 of this annual report.
 
                                         
    Year Ended December 31,  
    2010     2009(1)     2008(1)     2007     2006  
    (In thousands, except per share data)  
 
Statements of Operations Data:
                                       
Revenues:
                                       
Electricity
  $ 291,820     $ 252,621     $ 251,373     $ 215,969     $ 195,483  
Product
    81,410       159,389       92,577       79,950       73,454  
                                         
Total revenues
    373,230       412,010       343,950       295,919       268,937  
                                         
Cost of revenues:
                                       
Electricity
    242,326       179,101       169,297       148,698       124,356  
Product
    53,277       112,450       72,755       68,036       51,215  
                                         
Total cost revenues
    295,603       291,551       242,052       216,734       175,571  
                                         
Gross margin:
    77,627       120,459       101,898       79,185       93,366  
Operating expenses:
                                       
Research and development expenses
    10,120       10,502       4,595       3,663       2,983  
Selling and marketing expenses
    13,447       14,584       10,885       10,645       10,361  
General and administrative expenses
    27,442       26,412       25,938       21,416       18,094  
Write-off of unsuccessful exploration activities
    3,050       2,367       9,828              
                                         
Operating income
    23,568       66,594       50,652       43,461       61,928  
Other income (expense):
                                       
Interest income
    343       639       3,118       6,565       6,560  
Interest expense, net
    (40,473 )     (16,241 )     (14,945 )     (29,745 )     (30,961 )
Foreign currency translation and transaction gains (losses)
    1,557       (1,695 )     (4,421 )     (1,339 )     (704 )
Impairment of auction rate securities
    (137 )     (279 )     (4,195 )     (2,020 )      
Income attributable to sale of tax benefits
    8,729       15,515       18,118       6,488        
Gain on acquisition of controlling interest
    36,928                          
Gain from extinguishment of liability
          13,348                    
Other non-operating income
    267       479       771       890       694  
                                         
Income before income taxes and equity in income of investees
    30,782       78,360       49,098       24,300       37,517  
Income tax benefit (provision)
    1,098       (15,430 )     (5,310 )     (1,822 )     (6,403 )
Equity in income of investees, net
    998       2,136       1,725       4,742       4,146  
                                         
Income from continuing operations
    32,878       65,066       45,513       27,220       35,260  
Discontinued operations:
                                       
Income (loss) from discontinued operations, net of related tax
    14       3,487       (2,221 )            
Gain on sale of a subsidiary in New Zealand, net of related tax
    4,336                          
                                         
Net income
    37,228       68,553       43,292       27,220       35,260  
Net loss (income) attributable to noncontrolling interest
    90       298       316       156       (813 )
                                         
Net income attributable to the Company’s stockholders
  $ 37,318     $ 68,851     $ 43,608     $ 27,376     $ 34,447  
                                         
 


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    Year Ended December 31,  
    2010     2009(1)     2008(1)     2007     2006  
          (In thousands, except per share data)        
 
Earnings per share attributable to the Company’s stockholders:
                                       
Basic:
                                       
Income from continuing operations
  $ 0.72     $ 1.44     $ 1.04     $ 0.71     $ 1.00  
Discontinued operations
    0.10       0.08       (0.05 )            
                                         
Net income
  $ 0.82     $ 1.52     $ 0.99     $ 0.71     $ 1.00  
                                         
Diluted:
                                       
Income from continuing operations
  $ 0.72     $ 1.43     $ 1.03     $ 0.70     $ 0.99  
Discontinued operations
    0.10       0.08       (0.05 )            
                                         
Net income
  $ 0.82     $ 1.51     $ 0.98     $ 0.70     $ 0.99  
                                         
Weighted average number of shares used in computation of earnings per share attributable to the Company’s stockholders:
                                       
Basic
    45,431       45,391       44,182       38,762       34,593  
                                         
Diluted
    45,452       45,533       44,298       38,880       34,707  
                                         
Cash dividend per share declared during the year
  $ 0.27     $ 0.25     $ 0.20     $ 0.22     $ 0.15  
                                         
Balance Sheet Data (at end of year):
                                       
Cash and cash equivalents
  $ 82,815     $ 46,307     $ 34,393     $ 47,227     $ 20,254  
Working capital
    66,932       55,652       3,296       22,337       34,429  
Property, plant and equipment, net (including construction-in-process)
    1,696,101       1,517,288       1,334,859       977,400       793,164  
Total assets
    2,043,328       1,864,193       1,630,976       1,277,368       1,160,102  
Long-term debt (including current portion)
    789,669       624,442       386,635       322,472       372,009  
Notes payable to Parent (including current portion)
          9,600       26,200       57,847       140,153  
Equity
    945,227       911,695       847,235       627,836       440,925  
 
 
(1) In January 2010, we sold our interest in our New Zealand subsidiary, GDL. As a result of such sale, the operations of GDL have been included in discontinued operations in the years ended December 31, 2009 and 2008.
 
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.

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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, 2010 and 2009, our consolidated power plants generated 3,762,283 MWh and 3,296,824 MWh, respectively.
 
For the year ended December 31, 2010, our Electricity Segment represented approximately 78.2% of our total revenues, while our Product Segment represented approximately 21.8% of our total revenues during such year. For the year ended December 31, 2009, our Electricity Segment represented approximately 61.3% of our total revenues, while our Product Segment represented approximately 38.7% of our total revenues during such year.
 
For the year ended December 31, 2010, our total revenues decreased by 9.4% (from $412.0 million to $373.2 million) over the previous year. Revenues from the Electricity Segment increased by 15.5%, while revenues from the Product Segment decreased by 48.9%.
 
For the year ended December 31, 2010, total Electricity Segment revenues from the sale of electricity by our consolidated power plants were $291.8 million, compared to $252.6 million for the year ended December 31, 2009. In addition, revenues from our 50% ownership of the Mammoth complex in the period from January 1, 2010 to August 1, 2010 (the date we acquired the remaining 50% interest in the Mammoth complex) and in the year ended December 31, 2009 were $5.7 million and $9.9 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. We believe that such Non-GAAP data is useful to the readers as it provides a more complete view of the scope of activities of the power plants that we operate. Our investment in the Mammoth complex prior to our acquisition of the remaining 50% interest was accounted for in our consolidated financial statements under the equity method, and the revenues were not included in our consolidated revenues for the period from January 1, 2010 to August 1, 2010 nor for the year ended December 31, 2009.
 
For the year ended December 31, 2010, revenues attributable to our Product Segment were $81.4 million, compared to $159.4 million during the year ended December 31, 2009, a decrease of 48.9%. As discussed below and in our previous quarterly reports, this decrease is attributable to the decline in our Product Segment customer orders. We expect a similar level of revenues from our Product Segment in 2011.
 
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 April 2012. The exception is the 25 MW 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, 2010, approximately 86.2% 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


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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. Substantially 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 and in the solar sector.
 
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:
 
  •  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 routinely look at acquisition opportunities.
 
  •  In the United States, we expect to continue to benefit from the increasing demand for renewable energy. Thirty-six 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 slowdown and will continue to create opportunities for us to expand existing power plants and build new power plants.


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  •  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. In January 2011, the first phase of the EPA’s “Tailoring Rule” took effect in almost all of the states, with the notable exception of the state of Texas. The Tailoring Rule sets thresholds for when permitting requirements under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs apply to certain major sources of greenhouse gas emissions. Federal legislation or additional federal regulations addressing climate change are possible. Several states and regions are already addressing climate change. For example, California’s state climate change law, AB 32, which was signed into law in September 2006, regulates most sources of greenhouse gas emissions and aims to reduce greenhouse gas emissions to 1990 levels by 2020. In 2008, the California Air Resources Board approved a Scoping Plan to carry out regulations implementing AB 32. In December 2010, the California Air Resources Board endorsed cap-and-trade regulation to reduce California’s greenhouse gas emissions under AB 32. The cap-and-trade regulation sets a statewide limit on emissions from sources responsible for emitting 80 percent of California’s greenhouse gases and according to the California Air Resources Board, will help establish a price signal needed to drive long-term investment in cleaner fuels and more efficient use of energy. 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 CO2 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-two other states have set greenhouse gas emissions targets or goals (Arizona, Colorado, Connecticut, Florida, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, 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 CO2 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, twenty-nine states and the District of Columbia have all adopted RPS and seven other states have adopted renewable portfolio goals. In California, Governor Arnold Schwarzenegger signed an Executive Order on September 15, 2009, requiring most retail sellers of electricity to derive at least 33% of retail sales from eligible renewable resources by 2020. On September 23, 2010, the California Air Resources Board adopted unanimously the 33% renewable electricity standard.
 
  •  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 impact our ability to secure new purchase orders from potential customers. The increased competition also may lead to a reduction in prices that we are able to charge for our binary equipment, which in turn may impact our profitability.


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  •  Our PPA for 25 MW in the Puna power plant 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. A decrease in the price of oil will result in a decrease in the incremental cost that the power purchaser avoids by not generating its electrical energy needs from oil, which will result in a reduction of the energy rate that we may charge under this PPA and any other variable energy rate in PPAs that we may enter into in the future.
 
  •  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 industry 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 any 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.
 
  •  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 except one of our current contracts (our Steamboat 1 power plant, which sells its electricity to Sierra Pacific Power Company on a year-by-year basis) 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.
 
  •  The Global Settlement, once it becomes effective, will affect all of our PPAs with Southern California Edison, which accounted for approximately 29.1%, 21.1% and 27.7% of our revenues during 2010, 2009 and 2008, respectively. Under the Global Settlement, we have basically two choices available to us:
 
  •  We can do nothing, in which case our existing PPAs will automatically convert to SRAC pricing beginning in May 2012.
 
  •  We can amend our existing PPAs, which must be done within 180 days of the effectiveness of the Global Settlement, to incorporate one of the pricing options provided by the terms of the Global Settlement. If we make this choice, our existing PPAs will reflect the selected pricing option until December 2014 and thereafter convert to SRAC.
 
We plan to amend our existing PPAs, and are still evaluating which of the pricing options to select, which may vary from one PPA to another. We anticipate this may expose our revenues from these PPAs to greater fluctuations and may adversely affect our revenues under these PPAs. Because of the uncertainties inherent in pricing based on one or more future market-based prices for energy, heat rates and avoided costs, such as


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future natural gas prices, it is not possible at this time to reliably estimate the potential impact on our revenues from these PPAs.
 
  •  In January 2011, the CPUC approved a program that allows investor-owned utilities to purchase tradeable renewable energy credits (TRECs) for purposes of compliance with the utility’s RPS obligations. A TREC is the environmental attribute of generated energy, and can be purchased and sold separately from the underlying energy itself. Under the CPUC decision, a utility can meet up to 25% of its annual RPS obligation with TRECs. TRECs can only be acquired from projects in the Western Electric Coordinating Council (WECC) region that are not directly connected to a California balancing authority. In addition, there is a cap on utility payments of $50 per MWH for each TREC. The CPUC has indicated that the percentage limits on TRECs, the cap on TREC pricing, and the limitations to eligibility in the TREC definition will be revisited in the future. Although we cannot predict at this time whether the new TREC program will have a significant impact on our operations or revenues, it may facilitate additional options when negotiating power purchase agreements and in selling electricity from our projects.
 
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 for 25 MW are impacted by the price of oil. Accordingly, our revenues for that power plant, which accounted for 8.6% and 6.3% of our total revenues for the years ended December 31, 2010 and 2009, respectively, may be volatile.
 
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.


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The following table sets forth a breakdown of our revenues for the years indicated:
 
                                                 
          % of Revenues for Period
 
    Revenues in Thousands     Indicated  
    Year Ended December 31,     Year Ended December 31,  
    2010     2009     2008     2010     2009     2008  
 
Revenues
                                               
Electricity
  $ 291,820     $ 252,621     $ 251,373       78.2 %     61.3 %     73.1 %
Product
    81,410       159,389       92,577       21.8       38.7       26.9  
                                                 
Total
  $ 373,230     $ 412,010     $ 343,950       100.0 %     100.0 %     100.0 %
                                                 
 
Geographical breakdown of revenues
 
The following table sets forth the geographic breakdown of the revenues attributable to our Electricity Segment and Product Segment for the years indicated:
 
                                                 
          % of Revenues for Period
 
    Revenues in Thousands     Indicated  
    Year Ended December 31,     Year Ended December 31,  
    2010     2009     2008     2010     2009     2008  
 
Electricity Segment:
                                               
United States
  $ 220,107     $ 182,219     $ 206,795       75.4 %     72.1 %     82.3 %
Foreign
    71,713       70,402       44,578       24.6       27.9       17.7  
                                                 
Total
  $ 291,820     $ 252,621     $ 251,373       100.0 %     100.0 %     100.0 %
                                                 
Product Segment:
                                               
United States
  $ 10,177     $ 63,735     $ 41,863       12.5 %     40.0 %     45.2 %
Foreign
    71,233       95,654       50,714       87.5       60.0       54.8  
                                                 
Total
  $ 81,410     $ 159,389     $ 92,577       100.0 %     100.0 %     100.0 %
                                                 
 
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 plants, the Mammoth complex, the Ormesa complex, and the North Brawley 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, and insurance. In our California power plants our principal cost of revenues also include 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


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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, 2010, royalties constituted 3.6% of the Electricity Segment revenues, compared to approximately 3.3% in the year ended December 31, 2009.
 
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, 2010 increased to $82.8 million from $46.3 million as of December 31, 2009. This increase is principally due to: (i) the issuance of an aggregate principal amount of $142.0 million of Senior Unsecured Bonds on August 3, 2010; (ii) receipt of $108.3 million received in September 2010 for Specified Energy Property in Lieu of Tax Credits relating to our North Brawley geothermal power plant under Section 1603 of the ARRA; (iii) $101.4 million derived from operating activities during the year ended December 31, 2010; (iv) a net increase of $55.5 million in amounts drawn under revolving credit lines with commercial banks; (v) proceeds in the amount of $20.0 million from long-term loan agreements with a group of institutional investors; (vi) $19.6 million received from the sale of GDL; and (vii) a net increase of $17.7 million in restricted cash and cash equivalents. The increase in our cash resources was partially offset by: (i) our use of $283.3 million of cash resources to fund capital expenditures; (ii) net payment of $64.5 million for the acquisition of the remaining 50% interest in Mammoth Pacific ($72.5 million purchase price less $8.0 million available cash in such subsidiary at the acquisition date); and (iii) $61.8 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, 2010 was $402.5 million, as described below in the section entitled “Liquidity and Capital Resources”, of which we utilized $253.4 million (including $63.9 million of letters of credit) as of December 31, 2010.
 
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 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


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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. Revenues generated from engineering and operating services and sales of products and parts are recorded once the service is provided or product delivery is made, as applicable.
 
  •  Property, Plant and Equipment.  We capitalize all costs associated with the acquisition, development and construction of power plant facilities. Major improvements are capitalized and repairs and maintenance (including major maintenance) costs are expensed. We estimate the useful life of our power plants to range between 25 and 30 years. Such estimates are made by management based on factors such as prior operations, the terms of the underlying PPAs, geothermal resources, the location of the assets and specific power plant characteristics and designs. Changes in such estimates could result in useful lives which are either longer or shorter than the depreciable lives of such assets. We periodically re-evaluate the estimated useful life of our power plants and revise the remaining depreciable life on a prospective basis.
 
We capitalize costs incurred in connection with the exploration and development of geothermal resources beginning when we acquire land rights to the potential geothermal resource. Prior to acquiring land rights, we make an initial assessment that an economically feasible geothermal reservoir is probable on that land using available data and external assessments vetted through our exploration department and occasionally outside service providers. Costs incurred prior to acquiring land rights are expensed. It normally takes 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. If we decide to abandon a site, all previously capitalized costs associated with the exploration project are written off.
 
Our assessment of economic viability of an exploration project involves significant management judgment and uncertainties as to whether a commercially viable resource exists at the time we acquire land rights and begin to capitalize such costs. As a result, it is possible that our initial assessment of a geothermal resource may be incorrect and we would have to write-off costs associated with the project that were previously capitalized. During the years ended December 31, 2010, 2009 and, 2008, we determined that the geothermal resource at four of our exploration projects would not support commercial operations and abandoned the sites. As a result of this determination, we expensed $3,050,000, $2,367,000, and $9,828,000 of capitalized costs during the years ended December 31, 2010, 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 $54,697,000 and $33,617,000 at December 31, 2010 and 2009, respectively. Of this amount, $33,600,000 and $15,867,000 relates to up-front bonus payments at December 31, 2010 and 2009, respectively.


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  •  Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of.  We evaluate long-lived assets, such as property, plant and equipment, 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 in the future, we will test for impairment at the complex level.
 
Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated future net undiscounted cash flows expected to be generated by the asset. The significant assumptions that we use in estimating our undiscounted future cash flows include: (i) projected generating capacity of the power plant and rates to be received under the respective PPA; and (ii) projected operating expenses of the relevant power plant. Estimates of future cash flows used to test recoverability of a long-lived asset under development also include cash flows associated with all future expenditures necessary to develop the asset. If future cash flows are less than the assumptions we used in such estimates, we may incur impairment losses in the future that could be material to our financial condition and/or results of operations.
 
If our assets are considered to be impaired, the impairment to be recognized is 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.
 
The North Brawley power plant (North Brawley), which is under development, was tested for impairment in the current year due to the low output and higher than expected operating costs. Based on these indicators, we tested North Brawley for recoverability by estimating its future cash flows taking into consideration the various outcomes from different generating capacities, rates to be received under the PPA through the end of its term and expected market rates thereafter, possible penalties for underperformance during periods when the plant is expected to operate below the stated capacity in the PPA, projected capital expenditures to complete development of the plant and projected operating expenses over the life of the plant. We applied a probability-weighted approach and considered alternative courses of action.
 
Using a probability-weighted approach, the estimated undiscounted cash flows exceed the carrying value of the plant ($245 million as of December 31, 2010) by approximately $46 million and therefore, no impairment occurred. Estimated undiscounted cash flow are subject to significant uncertainties. If actual cash flows differ from our current estimates due to factors that include, among others, if the plant’s generating capacity is less than approximately 45 MW, or if the capital expenditures required to complete development of the plant and/or future operating costs exceed the level of our current projections, a material impairment write-down may be required in the future.
 
  •  Obligations Associated with the Retirement of Long-Lived Assets.  We record the fair market value of legal liabilities related to the retirement of our assets in the period in which such liabilities are incurred. Our liabilities


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  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, more likely than not, and therefore 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 deferred tax assets as of December 31, 2010, net of an immaterial valuation allowance related to state income taxes, 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, 2010, we adopted the amended consolidation guidance for variable interest entities. As to the impact of the adoption of this amendment on the consolidated financial statements and the additional disclosure in such consolidated financial statements, see Note 6 to our consolidated financial statements set forth in Item 8 of this annual report.
 
On July 1, 2010, we adopted an accounting standards update that amends and clarifies the guidance on how entities should evaluate credit derivatives embedded in beneficial interests in securitized financial assets. The adoption of this accounting standards update resulted in a reclassification to retained earnings with an offset to other comprehensive income effective July 1, 2010.
 
See Note 1 to our consolidated financial statements set forth in Item 8 of this annual report for additional information regarding new accounting pronouncements.


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Results of Operations
 
Our historical operating results in dollars and as a percentage of total revenues are presented below. A comparison of the different years described below may be of limited utility due to 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.
 
                         
    Year Ended December 31,  
    2010     2009(1)     2008(1)  
    (In thousands, except per share data)  
 
Statements of Operations Historical Data:
                       
Revenues:
                       
Electricity
  $ 291,820     $ 252,621     $ 251,373  
Product
    81,410       159,389       92,577  
                         
      373,230       412,010       343,950  
                         
Cost of revenues:
                       
Electricity
    242,326       179,101       169,297  
Product
    53,277       112,450       72,755  
                         
      295,603       291,551       242,052  
                         
Gross margin:
                       
Electricity
    49,494       73,520       82,076  
Product
    28,133       46,939       19,822  
                         
      77,627       120,459       101,898  
Operating expenses:
                       
Research and development expenses
    10,120       10,502       4,595  
Selling and marketing expenses
    13,447       14,584       10,885  
General and administrative expenses
    27,442       26,412       25,938  
Write-off of unsuccessful exploration activities
    3,050       2,367       9,828  
                         
Operating income
    23,568       66,594       50,652  
Other income (expense):
                       
Interest income
    343       639       3,118  
Interest expense, net
    (40,473 )     (16,241 )     (14,945 )
Foreign currency translation and transaction gains (losses)
    1,557       (1,695 )     (4,421 )
Impairment of auction rate securities
    (137 )     (279 )     (4,195 )
Income attributable to sale of tax benefits
    8,729       15,515       18,118  
Gain on acquisition of controlling interest
    36,928              
Gain from extinguishment of liability
          13,348        
Other non-operating income, net
    267       479       771  
                         
Income from continuing operations, before income taxes and equity in income of investees
    30,782       78,360       49,098  
Income tax benefit (provision)
    1,098       (15,430 )     (5,310 )
Equity in income of investees, net
    998       2,136       1,725  
                         
Income from continuing operations
    32,878       65,066       45,513  
Discontinued operations:
                       
Income (loss) from discontinued operations, net of related tax
    14       3,487       (2,221 )
Gain on sale of of a subsidiary in New Zealand, net of related tax
    4,336              
                         
Net income
    37,228       68,553       43,292  
Net loss attributable to noncontrolling interest
    90       298       316  
                         
Net income attributable to the Company’s stockholders
  $ 37,318     $ 68,851     $ 43,608  
                         
Earnings per share attributable to the Company’s stockholders:
                       
Basic:
                       
Income from continuing operations
  $ 0.72     $ 1.44     $ 1.04  
Discontinued operations
    0.10       0.08       (0.05 )
                         
Net income
  $ 0.82     $ 1.52     $ 0.99  
                         
Diluted:
                       
Income from continuing operations
  $ 0.72     $ 1.43     $ 1.03  
Discontinued operations
    0.10       0.08       (0.05 )
                         
Net income
  $ 0.82     $ 1.51     $ 0.98  
                         
Weighted average number of shares used in computation of earnings per share attributable to the Company’s stockholders:
                       
Basic
    45,431       45,391       44,182  
                         
Diluted
    45,452       45,533       44,298  
                         


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    Year Ended December 31,  
    2010     2009(1)     2008(1)  
 
Statements of Operations Percentage Data:
                       
Revenues:
                       
Electricity
    78.2 %     61.3 %     73.1 %
Product
    21.8       38.7       26.9  
                         
      100.0       100.0       100.0  
                         
Cost of revenues:
                       
Electricity
    83.0       70.9       67.3  
Product
    65.4       70.6       78.6  
                         
      79.2       70.8       70.4  
                         
Gross margin:
                       
Electricity
    17.0       29.1       32.7  
Product
    34.6       29.4       21.4  
                         
      20.8       29.2       29.6  
Operating expenses:
                       
Research and development expenses
    2.7       2.5       1.3  
Selling and marketing expenses
    3.6       3.5       3.2  
General and administrative expenses
    7.4       6.4       7.5  
Write-off of unsuccessful exploration activities
    0.8       0.6       2.9  
                         
Operating income
    6.3       16.2       14.7  
Other income (expense):
                       
Interest income
    0.1       0.2       0.9  
Interest expense, net
    (10.8 )     (3.9 )     (4.3 )
Foreign currency translation and transaction gains (losses)
    0.4       (0.4 )     (1.3 )
Impairment of auction rate securities
    (0.0 )     (0.1 )     (1.2 )
Income attributable to sale of tax benefits
    2.3       3.8       5.3  
Gain on acquisition of controlling interest
    9.9       0.0       0.0  
Gain from extinguishment of liability
    0.0       3.2       0.0  
Other non-operating income, net
    0.1       0.1       0.2  
                         
Income from continuing operations, before income taxes and equity in income of investees
    8.2       19.0       14.3  
Income tax benefit (provision)
    0.3       (3.7 )     (1.5 )
Equity in income of investees, net
    0.3       0.5       0.5  
                         
Income from continuing operations
    8.8       15.8       13.2  
Discontinued operations:
                       
Income (loss) from discontinued operations, net of related tax
    0.0       0.8       (0.6 )
Gain on sale of of a subsidiary in New Zealand, net of related tax
    1.2       0.0       0.0  
                         
Net income
    10.0       16.6       12.6  
Net loss attributable to noncontrolling interest
    0.0       0.1       0.1  
                         
Net income attributable to the Company’s stockholders
    10.0 %     16.7 %     12.7 %
                         
 
 
(1) In January 2010, we sold our interest in our New Zealand subsidiary, GDL. As a result of such sale, the operations of GDL have been included in discontinued operations in the years ended December 31, 2009 and 2008.


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Comparison of the Year Ended December 31, 2010 and the Year Ended December 31, 2009
 
Total Revenues
 
Total revenues for the year ended December 31, 2010 were $373.2 million, compared to $412.0 million for the year ended December 31, 2009, which represented a 9.4% decrease in total revenues. This decrease is attributable to our Product Segment whose revenues decreased by 48.9% from the same period in 2009 (for the reasons discussed below). Revenues in our Electricity Segment increased by 15.5% from the same period in 2009.
 
Electricity Segment
 
Revenues attributable to our Electricity Segment for the year ended December 31, 2010 were $291.8 million, compared to $252.6 million for the year ended December 31, 2009, which represented a 15.5% increase in such revenues. The increase is primarily a result of increased electricity generation at most of our power plants from 3,296,824 MWh in the year ended December 31, 2009 to 3,762,283 MWh in the year ended December 31, 2010, an increase of 14.1%. The most significant contributors to the increase in our electricity revenues were: (i) an increase in the generation of the Puna power plant following repair work that was completed in the second quarter of 2010; (ii) the placement in service of our North Brawley power plant in January 2010, with revenues of $15.0 million in the year ended December 31, 2010; and (iii) the consolidation of the Mammoth complex effective August 2, 2010, with revenues of $7.6 million in the period from August 2, 2010 to December 31, 2010, resulting from the acquisition of the remaining 50% interest in Mammoth Pacific. The increase in our Electricity Segment revenues is also attributable to a slight increase in the average revenue rate of our electricity portfolio from $77 per MWh in the year ended December 31, 2009 to $78 per MWh in the year ended December 31, 2010.
 
Product Segment
 
Revenues attributable to our Product Segment for the year ended December 31, 2010 were $81.4 million, compared to $159.4 million for the year ended December 31, 2009, which represented a 48.9% decrease in such revenues. This decrease in our product revenue is a result of reduced Product Segment customer orders for the year ended December 31, 2010. We expect a similar level of revenues from our Product Segment in 2011.
 
Total Cost of Revenues
 
Total cost of revenues for the year ended December 31, 2010 was $295.6 million, compared to $291.6 million for the year ended December 31, 2009, which represented a 1.4% increase in total cost of revenues. This increase is attributable to an increase in our Electricity Segment cost of revenues, which was offset by a decrease in our Product Segment cost of revenues, as discussed below. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2010 was 79.2%, compared to 70.8% for the year ended December 31, 2009. This increase is mainly attributable to high costs in our North Brawley power plant, as described below, as well as the lower volume of Product Segment revenues.
 
Electricity Segment
 
Total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2010 was $242.3 million, which include $39.6 million (including depreciation) related to our North Brawley power plant, compared to $179.1 million for the year ended December 31, 2009, which represented a 35.3% increase in total cost of revenues for such segment. The increase over the same period last year is mainly attributable to our North Brawley power plant which was placed in service in January 2010. We have incurred high costs (including depreciation) associated with operating and maintaining this power plant, which has a design capacity of 50 MW but is currently operating at a reduced capacity. The higher costs in the North Brawley power plant increased the cost per MWh for the year ended December 31, 2010, compared to the year ended December 31, 2009. Further details on the operational issues at the North Brawley power plant are discussed in Item 1 — “Business” under the heading “Description of Our Power Plants” of this annual report. We expect to have high operation expenses at the North Brawley power plant for at least the next few quarters. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2010 was 83.0%, compared to 70.9% for the year ended December 31, 2009.


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Product Segment
 
Total cost of revenues attributable to our Product Segment for the year ended December 31, 2010 was $53.3 million, compared to $112.5 million for the year ended December 31, 2009, which represented a 52.6% decrease in total cost of revenues related to such segment. This decrease is attributable to the decrease in product revenues, as described above. As a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment for the year ended December 31, 2010 decreased from 70.6% for the year ended December 31, 2009 to 65.4% for the year ended December 31, 2010. This percentage decrease is attributable to the removal of a contingency relating to a project that was substantially completed in the second quarter of 2010.
 
Research and Development Expenses
 
Research and development expenses for the year ended December 31, 2010 were $10.1 million, compared to $10.5 million for the year ended December 31, 2009, which represented a 3.6% decrease. Our research and development activities during the year ended December 31, 2010 included primarily: (i) an experimental REG plant specifically designed to use the residual energy from the vaporization process at LNG regasification terminals, including developing and building a unit at a customer’s premises in Spain. (ii) continued development of enhanced geothermal systems (EGS); and (iii) development of a solar thermal system for the production of electricity. Construction of the experimental REG plant commenced in the third quarter of 2010 and is expected to be completed in the first half of 2011. 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 tests, we will be paid by the customer an amount of approximately $15.0 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 $0.9 million and $1.3 million for the years ended December 31, 2010 and 2009, respectively, with respect to the EGS project. We expect research and development expenses to decrease further in 2011 as a result of the completion of the experimental REG plant project.
 
Selling and Marketing Expenses
 
Selling and marketing expenses for the year ended December 31, 2010 were $13.4 million, compared to $14.6 million for the year ended December 31, 2009, which represented an 7.8% decrease. The decrease was due primarily to the decrease in Product Segment revenues. Selling and marketing expenses for the year ended December 31, 2010 constituted 3.6% of total revenues for such period, compared to 3.5% for the year ended December 31, 2009.
 
General and Administrative Expenses
 
General and administrative expenses for the year ended December 31, 2010 were $27.4 million, compared to $26.4 million for the year ended December 31, 2009, which represented a 3.9% increase. General and administrative expenses for the year ended December 31, 2010 constituted 7.4% of total revenues for such year, compared to 6.4% for the year ended December 31, 2009.
 
Write-off of Unsuccessful Exploration Activities
 
Write-off of unsuccessful exploration activities for the year ended December 31, 2010 was $3.1 million, compared to $2.4 million for the year ended December 31, 2009. Write-off of unsuccessful exploration activities for the year ended December 31, 2010 relates to the Gabbs Valley exploration project in Nevada, which we determined in the second quarter of 2010 would not support commercial operations. Write-off of unsuccessful exploration activities for the year ended December 31, 2009 relates to the Rock Hills exploration project in Nevada, which we determined in the third quarter of 2009 would not support commercial operations.
 
Operating Income
 
Operating income for the year ended December 31, 2010 was $23.6 million, compared to $66.6 million for the year ended December 31, 2009. Such decrease of $43.0 million in operating income was principally attributable to a decrease in the total gross margin due to the decrease in Product Segment revenues and the increase in Electricity


102


 

Segment cost of revenues. Operating income attributable to our Electricity Segment for the year ended December 31, 2010 was $12.8 million, compared to $45.3 million for the year ended December 31, 2009, mainly due to the increase in electricity cost of revenues, as explained above. Operating income attributable to our Product Segment for the year ended December 31, 2010 was $10.8 million, compared to $21.3 million for the year ended December 31, 2009, mainly due to the decrease in product revenues, as explained above.
 
Interest Expense, Net
 
Interest expense, net, for the year ended December 31, 2010 was $40.5 million, compared to $16.2 million for the year ended December 31, 2009, which represented a 149.2% increase. The $24.2 million increase is primarily due to: (i) a decrease of $17.9 million in interest capitalized to projects as a result of decreased aggregate investment in projects under construction; (ii) an increase in interest expenses related to our long-term project finance loans of the Olkaria III and Amatitlan power plants; (iii) borrowings under our revolving credit lines with banks; (iv) loan agreements with institutional investors and a commercial bank; and (v) issuance of Senior Unsecured Bonds on August 3, 2010, as discussed below. The increase was partially offset by a decrease in interest expense as a result of the acquisition of a 30% interest in the Class B membership units of OPC on October 30, 2009 by our subsidiary, Ormat Nevada, as well as principal repayments.
 
Foreign Currency Translation and Transaction Gains (Losses)
 
Foreign currency translation and transaction gains for the year ended December 31, 2010 were $1.6 million, compared to foreign currency translation and transaction losses of $1.7 million for the year ended December 31, 2009. The $3.3 million increase is primarily due to an increase in gains on forward foreign exchange transactions which do not qualify as hedge transactions for accounting purposes.
 
Income Attributable to Sale of Tax Benefits
 
Income attributable to the sale of tax benefits to institutional equity investors (as described in “OPC Transaction” below) for the year ended December 31, 2010 was $8.7 million, compared to $15.5 million for the year ended December 31, 2009. 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 in October 2009, as described under “Gain from Extinguishment of Liability” below.
 
Gain on Acquisition of Controlling Interest
 
Gain on acquisition of controlling interest for the year ended December 31, 2010 was $36.9 million. This gain relates to the acquisition of the remaining 50% interest in Mammoth Pacific. The acquisition-date fair value of the previous 50%-equity interest was $64.9 million. In the year ended December 31, 2010, we recognized a pre-tax gain of $36.9 million ($22.4 million after tax), which is equal to the difference between the acquisition-date fair value of the initial investment in Mammoth Pacific and the acquisition-date carrying value of such investment.
 
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 30% 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 ($8.2 million after tax) in the year ended December 31, 2009. In addition, an amount of approximately $1.1 million was classified in the year ended December 31, 2009 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 benefit for the year ended December 31, 2010 was $1.1 million, compared to income tax provision of $15.4 million for the year ended December 31, 2009. The effective tax rate for the year ended December 31, 2010 was 3.6% compared to 19.7% for the year ended December 31, 2009. The decrease in the effective tax rate primarily resulted from the higher impact of PTCs on the effective tax rate for the year ended December 31, 2010 due to our low pretax income from continuing operations.
 
Equity in Income of Investees
 
Our participation in the income generated from our investees for the year ended December 31, 2010 was $1.0 million, compared to $2.1 million for the year ended December 31, 2009. The amount is derived mainly from our 50% ownership of the Mammoth complex which was included in the Company’s consolidated financial statements effective August 2, 2010, as a result of our acquisition of the remaining 50% interest in Mammoth Pacific. For the year ended December 31, 2010, the amount represents our share in the loss of the Mammoth complex in the period from January 1, 2010 to August 1, 2010.
 
Income from Continuing Operations
 
Income from continuing operations for the year ended December 31, 2010 was $32.9 million, compared to $65.1 million for the year ended December 31, 2009. Such decrease of $32.2 million in income from continuing operations was principally attributable to: (i) a $43.0 million decrease in operating income; (ii) a $24.2 million increase in interest expense, net; (iii) a $6.8 million decrease in income attributable to the sale of tax benefits; and (iv) gain from extinguishment of liability of $13.3 million in the year ended December 31, 2009. This was partially offset by: (i) a $3.3 million increase in foreign currency transaction and translation gains; (ii) gain on acquisition of controlling interest of $36.9 million in the year ended December 31, 2010; and (iii) a $16.5 million decrease in income tax provision.
 
Discontinued Operations
 
In January 2010, a former shareholder of GDL exercised a call option to purchase from us our shares in GDL for approximately $2.8 million. We did not exercise our right of first refusal, and therefore we transferred our shares in GDL to the former shareholder. As a result, we recorded an after-tax gain of $4.3 million in the year ended December 31, 2010. The operations of GDL have been included in discontinued operations for all periods prior to the sale of GDL.
 
Net Income
 
Net income for the year ended December 31, 2010 was $37.2 million, compared to $68.6 million for the year ended December 31, 2009, which represents a decrease of 31.3 million. Such decrease in net income was principally attributable to the decrease in income from continuing operations in the amount of $32.2 million, as discussed above.
 
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 $412.0 million, compared to $344.0 million for the year ended December 31, 2008, which represented a 19.8% increase in total revenues. This increase was 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 0.5% from the same period in 2008.
 
Electricity Segment
 
Revenues attributable to our Electricity Segment for the year ended December 31, 2009 were $252.6 million, compared to $251.4 million for the year ended December 31, 2008, which represented a 0.5% increase in such revenues. This increase resulted from an increase in our electricity generation from 2,932,031 MWh in the year


104


 

ended December 31, 2008 to 3,296,824 MWh in the year ended December 31, 2009, an increase of 12.4%. Despite the 12.4% increase in our electricity generation, our electricity revenues increased by a modest 0.5% 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 $77 per MWh in the year ended December 31, 2009. The decrease in the average rate was 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”, an additional energy rate 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. In the United States, 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 electricity 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 undertook 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.
 
Total Cost of Revenues
 
Total cost of revenues for the year ended December 31, 2009 was $291.6 million, compared to $242.1 million for the year ended December 31, 2008, which represented a 20.4% increase in total cost of revenues. This increase was primarily attributable to the increase in the cost of revenues in our Product Segment, as discussed below. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2009 was 70.8% 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 $179.1 million, compared to $169.3 million for the year ended December 31, 2008, which represented a 5.8% 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 70.9%, compared to 67.3% 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 was 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 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.


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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 LNG 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. The research and development expenses are net of grants from the DOE in the amount of $1.3 million and $0.6 million for the years ended December 31, 2009 and 2008, respectively, 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 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 in Nevada, 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 in Nevada, 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 $66.6 million, compared to $50.7 million 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 $45.3 million, compared to $45.0 million for the year ended December 31, 2008. Operating income attributable to our Product Segment for the year ended December 31, 2009 was $21.3 million, compared to $5.7 million for the year ended December 31, 2008.
 
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 was 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.


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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 was 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 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.
 
Foreign Currency Translation and Transaction Losses
 
Foreign currency translation and transaction losses for the year ended December 31, 2009 were $1.7 million, compared to $4.4 million for the year ended December 31, 2008. The $2.7 million decrease was primarily due to a decrease in losses on forward foreign exchange transactions which do not qualify as hedge transactions for accounting purposes.
 
Impairment 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 attributable to the sale of tax benefits to institutional equity investors (as described in “OPC Transaction” below) 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 was 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 in October 2009, 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 30% 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 ($8.8 million after tax) in the year ended December 31, 2009. In addition, an amount of approximately $1.1 million has been classified in the year ended December 31, 2009 from noncontrolling interest to additional paid-in capital representing the 1.5% residual interest of Lehman-OPC’s Class B membership units.
 
Income Taxes
 
Income tax provision for the year ended December 31, 2009 was $15.4 million, compared to $5.3 million for the year ended December 31, 2008. The effective tax rate for the year ended December 31, 2009 and 2008 was 19.7% and 10.8%, 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.


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Income from Continuing Operations
 
Income from continuing operations for year ended December 31, 2009 was $65.1 million, compared to $45.5 million for year ended December 31, 2008. Such increase of $19.6 million in income from continuing operations was principally attributable to: (i) an increase of $15.9 million in our operating income; (ii) a decrease of $2.7 million in foreign currency transaction and translation losses; (iii) a decrease of $3.9 million in impairment of auction rate securities; and (iv) a $13.3 million gain from extinguishment of liability. This increase was partially offset by: (i) a $10.1 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.
 
Discontinued Operations
 
In January 2010, a former shareholder of GDL exercised a call option to purchase from us our shares in GDL for approximately $2.8 million. We did not exercise our right of first refusal and, therefore, we transferred our shares in GDL to the former shareholder. The operations of GDL have been included in discontinued operations for all periods prior to the sale of GDL.
 
Net Income
 
Net income for the year ended December 31, 2009 was $68.6 million, compared to $43.3 million for the year ended December 31, 2008, which represents an increase of 58.4%. Such increase in net income was principally attributable to the increase in income from continuing operations in the amount of $19.6 million and to an increase of $5.7 million in income from discontinued operations, as discussed above.
 
Liquidity and Capital Resources
 
Our principal sources of liquidity have been derived from cash flows from operations, the issuance of our common stock in public and private offerings, proceeds from third party debt in the form of borrowings under credit facilities and private offerings, issuance by OFC and OrCal of their respective Senior Secured Notes, project financing (including the Puna lease and the OPC Transaction described below), and a cash grant we received under the ARRA in respect of the North Brawley power plant. We have utilized this cash to fund our acquisitions (including the acquisition of the remaining 50% ownership of the Mammoth complex in August 2010), to develop and construct power generation plants, and to meet our other cash and liquidity needs.
 
As of December 31, 2010, we have access to the following sources of funds: (i) $82.8 million in cash and cash equivalents; and (ii) $149.1 million of unused corporate borrowing capacity under existing lines of credit with different commercial banks.
 
Our estimated capital needs for 2011 include approximately $467 million for capital expenditures on new projects under development or construction, exploration activity, operating projects, and machinery and equipment, as well as $49.0 million for debt repayment.
 
We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) cash flows from our operations; (iii) proceeds of approximately $108 million that we received from the issuance of additional senior unsecured notes to institutional investors in February 2011 (see below); (iv) proceeds of $24.9 million from the sale by Ormat Nevada on February 3, 2011 of all its Class B membership units of OPC that it acquired on October 30, 2009 (see below); (v) additional borrowing capacity under future lines of credit with commercial banks that are under negotiations; (vi) future project financing and refinancing; and (vii) cash grants available to us under the ARRA in respect of new projects that will be placed in service before the end of 2013. Management believes that these sources will address our anticipated liquidity, capital expenditures, and other investment requirements. 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.


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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, 2010, OFC was in compliance with the covenants under the OFC Senior Secured Notes. As of December 31, 2010, there were $136.3 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 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, 2010, OrCal was in compliance with the covenants under the OrCal Senior Secured Notes. As of December 31, 2010, there were $95.6 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, 2010, OrPower 4 was in compliance with the covenants under the loan. As of December 31, 2010, $88.4 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


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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, 2010, Ortitlan was in compliance with the covenants under the loan. As of December 31, 2010, $39.0 million of the above loan was outstanding.
 
Senior Loan from IFC — Non-Recourse
 
Orzunil has a senior loan agreement with IFC. The loan, of which $1.7 million was outstanding as of December 31, 2010, has a fixed annual interest rate of 11.775%, and matures on November 15, 2011. There are various restrictive covenants under this senior loan, which include limitations on Orzunil’s ability to make distributions to its shareholders. As of December 31, 2010, Orzunil was in compliance with the covenants under this senior loan.
 
New Financing of our Projects
 
Financing of the North Brawley Power Plant
 
We refinanced a portion of the equity invested in the North Brawley power plant with the cash grant we received under the ARRA in September 2010. We expect that once we bring the power plant closer to its original design capacity, we will be able to refinance a portion of the remainder with long-term debt.
 
Financing for Jersey Valley, McGinness Hills and Tuscarora Projects in Nevada
 
Our subsidiary, Ormat Nevada, has engaged John Hancock to arrange senior secured construction and term loan facilities under a United States DOE loan guarantee program of up to $350 million for three geothermal projects currently under construction in Nevada. The three projects are the Jersey Valley, McGinness Hills, and Tuscarora geothermal projects. Construction of all three projects has already commenced with commercial operation of the first phase of each project expected between 2011 and 2013.
 
The availability of the credit facilities is subject to various conditions, including execution of mutually satisfactory documentation and approval of the DOE.
 
John Hancock and the DOE are conducting a due diligence review of the three projects. Upon the satisfactory completion of the review, John Hancock and the DOE will consider issuing a conditional commitment which may lead to a loan guarantee, although we have no assurance this will occur.
 
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, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of Union Bank.


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As of December 31, 2010, letters of credit in the aggregate amount of $34.4 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 $365.0 million. Under the terms of these credit agreements, we or our Israeli subsidiary, Ormat Systems, can request: (i) extensions of credit in the form of loans and/or the issuance of one or more letters of credit in the amount of up to $315.0 million; and (ii) the issuance of one or more letters of credit in the amount of up to $50.0. The credit agreements mature between May 2011 and September 2013. 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. Credit agreements in the amount of $165.0 million are due to expire in 2011. We are currently negotiating the extension of these credit agreements for up to three years. We anticipate that these extensions will include an increase in the annual average interest rates.
 
As of December 31, 2010, loans in the total amount of $189.5 million were outstanding, and letters of credit with an aggregate stated amount of $29.5 million were issued and outstanding under such credit agreements. The $189.5 million in loans are for terms of three months or less and bear interest at an annual weighted average rate of 2.03% as of December 31, 2010.
 
We have a $20.0 million term loan with a group of institutional investors, which matures on July 16, 2015, is payable in 12 semi-annual installments commencing January 16, 2010, and bears annual interest of 6.5%. As of December 31, 2010, $17.2 million was outstanding under this loan.
 
We have a $20.0 million term loan with a group of institutional investors, which matures on August 1, 2017, is payable in 12 semi-annual installments commencing February 1, 2012, and bears interest at 6-month LIBOR plus 5.0%. As of December 31, 2010, $20.0 million was outstanding under this loan.
 
We also have a $20.0 million term loan with a group of institutional investors, which matures on November 16, 2016, is payable in ten semi-annual installments commencing May 16, 2012, and bears annual interest of 5.75%. As of December 31, 2010, $20.0 million was outstanding under this loan.
 
We have a $50.0 million term loan with a commercial bank, which matures on November 10, 2014, and is payable in ten semi-annual installments commencing May 10, 2010, and bears interest at 6-month LIBOR plus 3.25%. As of December 31, 2010, $40.0 million was outstanding under this loan.
 
We have an aggregate principal amount of approximately $250.0 million of Senior Unsecured Bonds issued and outstanding. We issued approximately $142.0 million of these bonds in August 2010 and an additional $107.5 million in February 2011. Subject to early redemption, the principal of the bonds is repayable in a single bullet payment upon the final maturity of the bonds on August 1, 2017. The bonds bear interest at a fixed rate of 7% per annum, payable semi-annually. The bonds that we issued in February 2011 were issued at a premium which reflects an effective fixed interest of 6.75% per annum. We issued the bonds outside the United States to investors who are not “U.S. persons” in an unregistered offering pursuant to, and subject to the requirements of, Regulation S under the Securities Act.
 
Our obligations under the credit agreements, the loan agreements, and the trust instrument governing the bonds, described above, are unsecured, but we are subject to a negative pledge in favor of the banks and the other lenders and certain other restrictive covenants. These include, among other things, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of our assets, or a change of control in our ownership structure. Some of the credit agreements, the loan agreements, and the trust instrument contain cross-default provisions with respect to other material indebtedness owed by us to any third party. In some cases, we have agreed to maintain certain financial ratios such as a debt service coverage ratio, a debt to equity ratio, and a debt to adjusted EBITDA ratio. There are also certain restrictions on distribution of dividends. The failure to perform or observe any of the covenants set forth in such agreements, subject to various cure periods, would result in the occurrence of an event of default and would enable the lenders to accelerate all amounts due under each such agreement.


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We are currently in compliance with our covenants with respect to the credit agreements, the loan agreements and the trust instrument, and believe that the restrictive covenants, financial ratios and other terms of any of our (or Ormat Systems’) full-recourse bank credit agreements will not materially impact our business plan or 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, 2010, such banks have issued on our behalf letters of credit totaling $17.1 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 five other commercial banks as described above under “Full-Recourse Third Party Debt”. As of December 31, 2010, letters of credit in the aggregate amount of $67.0 million remained issued and outstanding under the Union Bank credit agreement and our other agreements with commercial banks.
 
Puna Power Plant 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 payments of $83.0 million by such financing parties to PGV , which are accounted for as deferred lease income.
 
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 our Desert Peak 2, Steamboat Hills, and Galena 2 power plants. The investors paid $71.8 million at the first closing. The second closing under the agreements occurred in 2008 and covered the Galena 3 power plant. The investors paid $63.0 million at the second closing.
 
Ormat Nevada continues to operate and maintain the power plants. Under the agreements, Ormat Nevada initially received all of the distributable cash flow generated by the power plants until it recovered the capital that it invested in the power plants, which occurred in the fourth quarter of 2010, while the investors receive substantially all of the PTCs and the taxable income or loss, and receive the distributable cash flow after Ormat Nevada 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


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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 and is not subject to mandatory redemption or guaranteed payments.
 
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. The investors own all of the Class B membership units, which represent 25% of the voting rights of OPC. Other than in respect of customary protective rights, all operational decisions in OPC are decided by the vote of a majority of the membership units. Following the Flip Date, Ormat Nevada’s voting rights will increase to 95% and the investor’s voting rights will decrease to 5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the Flip Date and therefore has continued to consolidate OPC.
 
On October 30, 2009, Ormat Nevada acquired from Lehman-OPC all of the Class B membership units of OPC held by Lehman-OPC pursuant to a right of first offer for a purchase price of $18.5 million. As a result of that transaction, Lehman-OPC has no further interest in OPC.
 
On February 3, 2011, Ormat Nevada sold to JPM Capital Corporation (JPM) all of the Class B membership units of OPC that it had acquired on October 30, 2009 for a sale price of $24.9 million in cash. We will not record any gain from the sale of our Class B membership interests in OPC to JPM.
 
Liquidity Impact of Uncertain Tax Positions
 
As discussed in Note 19 to our consolidated financial statements set forth in Item 8 of this annual report, we have a liability associated with unrecognized tax benefits and related interest and penalties in the amount of approximately $5.4 million as of December 31, 2010. 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.
 
Dividend
 
The following are the dividends we declared during the past two years:
 
                 
    Dividend
       
    Amount
       
Date Declared   per Share   Record Date   Payment Date
 
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
May 5, 2010
  $ 0.05     May 18, 2010   May 25, 2010
August 4, 2010
  $ 0.05     August 17, 2010   August 26, 2010
November 2, 2010
  $ 0.05     November 17, 2010   November 30, 2010
February 22, 2011
  $ 0.05     March 15, 2011   March 24, 2011


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Historical Cash Flows
 
The following table sets forth the components of our cash flows for the relevant periods indicated:
 
                         
    Year Ended December 31,
    2010   2009   2008
    (In thousands)
 
Net cash provided by operating activities
  $ 101,403     $ 110,772     $ 116,949  
Net cash used in investing activities
    (203,820 )     (286,036 )     (398,991 )
Net cash provided by financing activities
    138,925       187,036       269,286  
Translation adjustments on cash and cash equivalents
          142       (78 )
Net change in cash and cash equivalents
    36,508       11,914       (12,834 )
 
For the Year Ended December 31, 2010
 
Net cash provided by operating activities for the year ended December 31, 2010 was $101.4 million, compared to $110.8 million for the year ended December 31, 2009. The net decrease of $9.4 million resulted primarily from: (i) a decrease in net income to $37.2 million in the year ended December 31, 2010, from $68.6 million in the year ended December 31, 2009, mainly as a result of the decrease in operating income, as described above; (ii) gain on acquisition of controlling interest of $36.9 million in the year ended December 31, 2010; (iii) a gain on sale of GDL of $6.4 million in the year ended December 31, 2010; and (iv) a net decrease in deferred income taxes of $10.1 million in the year ended December 31, 2010, compared to a net increase of $4.0 million in the year ended December 31, 2009. Such decrease was partially offset by: (i) an increase of $22.4 million in depreciation and amortization mainly due to the placement in service of our North Brawley power plant in January 2010, as described above; (ii) a gain from extinguishment of liability of $13.3 million in the year ended December 31, 2009; (iii) a net decrease in costs and estimated earnings in excess of billings on uncompleted contracts of $8.7 million in the year ended December 31, 2010, compared to a net increase of $20.0 million in the year ended December 31, 2009; and (iv) an increase in accounts payable and accrued expenses of $9.7 million in the year ended December 31, 2010, compared to a decrease of $2.1 million in the year ended December 31, 2009.
 
Net cash used in investing activities for the year ended December 31, 2010 was $203.8 million, compared to $286.0 million for the year ended December 31, 2009. The principal factors that affected our net cash used in investing activities during the year ended December 31, 2010 were: (i) capital expenditures of $283.3 million, primarily for our facilities under construction; and (ii) net payment of $64.5 million for acquisition of controlling interest in Mammoth Pacific ($72.5 million purchase price less $8.0 million available cash in such subsidiary at the acquisition date); offset by: (i) $108.3 million of cash grant received in September 2010 for Specified Energy Property in Lieu of Tax Credits relating to our North Brawley geothermal power plant under Section 1603 of the ARRA; (ii) $19.6 million cash received from the sale of GDL; and (iii) a $17.5 million decrease in restricted cash, cash equivalents and marketable securities.
 
Net cash provided by financing activities for the year ended December 31, 2010 was $138.9 million, compared to $187.0 million for the year ended December 31, 2009. The principal factors that affected the net cash provided by financing activities during the year ended December 31, 2010 were: (i) the issuance of an aggregate amount of approximately $142.0 million of Senior Unsecured Bonds on August 3, 2010; (ii) $20.0 million proceeds from a long-term loan agreement with a group of institutional investors; and (iii) $55.5 million increase in amounts drawn under revolving lines of credit from banks; offset by: (i) the repayment of long-term debt to our parent in the amount of $9.6 million; (ii) the repayment of debt to third parties in the amount of $52.2 million; and (iii) the payment of a dividend to our shareholders in the amount of $12.3 million.
 
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, 2009,


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compared to an increase of $13.5 million in the year ended December 31, 2008. 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 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 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.
 
Adjusted EBITDA
 
Adjusted EBITDA for the year ended December 31, 2010 decreased to $164.3 million, compared to $167.0 million for the year ended December 31, 2009. Adjusted EBITDA for the year ended December 31, 2009 increased to $167.0 million, compared to $121.9 million for the year ended December 31, 2008. 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. 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.


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The following table reconciles net cash provided by operating activities to EBITDA and adjusted EBITDA, for the years ended December 31 2010, 2009, and 2008:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands)  
 
Net cash provided by operating activities
  $ 101,403     $ 110,772     $ 116,949  
Adjusted for:
                       
Interest expense, net (excluding amortization of deferred financing costs)
    37,590       13,623       13,590  
Interest income
    (343 )     (639 )     (3,118 )
Income tax provision (benefit)
    908       16,924       4,358  
Adjustments to reconcile net income to net cash provided by operating activities (excluding depreciation and amortization)
    22,586       22,392     $ (13,529 )
                         
EBITDA
    162,144       163,072       118,250  
Interest, taxes, depreciation and amortization attributable to the Company’s equity in Mammoth-Pacific L.P. 
    2,115       3,891       3,636  
                         
Adjusted EBITDA
  $ 164,259     $ 166,963     $ 121,886  
                         
Net cash used in investing activities
  $ (203,820 )   $ (286,036 )   $ (398,991 )
                         
Net cash provided by financing activities
  $ 138,925     $ 187,036     $ 269,286  
                         
 
Capital Expenditures
 
Our capital expenditures primarily relate to two principal components: (i) the enhancement of our existing power plants; and (ii) the development and construction of new power plants. We expect that the following enhancements of our existing power plants and the construction of new power plants will be funded initially from internally generated cash or other available corporate resources, which we expect to subsequently refinance with limited or non-recourse debt at the project level.
 
We have estimated approximately $570 million in capital expenditures for construction of new projects that are still under construction and that are expected to be completed by 2013. We have invested approximately $122 million of such estimated amount as of December 31, 2010. We expect to invest an additional $232 million of such total in 2011. The remaining $216 million will be invested in 2012 and 2013.
 
We also estimate approximately $235 million in additional capital expenditures in 2011 to be allocated as follows: (i) $114 million in new projects under development; (ii) $19 million for enhancement of our operating power plants; (iii) $10 million in land acquisition; (iv) $46 million in exploration activities in various leases for geothermal resources in which we have started the exploration activity; (v) $36 million in new project development, provided that part or all of the aforementioned exploration activities succeed; and (vi) $10 million in enhancement of our production facilities.
 
Exposure to Market Risks
 
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 the Puna PPA for 25 MW) 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, that are impacted by natural gas prices which may decline. Decreases in the price of natural gas will result in a decrease in the incremental cost that the power purchaser avoids by not generating its electrical energy needs from natural gas, which will result in a reduction of the energy rate that we may charge. The Puna power plant is currently


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benefiting from energy prices which are higher than the floor under the Puna PPA for 25 MW as a result of the high fuel costs that impact HELCO’s avoided costs.
 
As of December 31, 2010, 65.4% of our consolidated long-term debt was in the form of fixed rate securities and therefore not subject to interest rate volatility risk. As of such date, 34.6% 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, 2010, $272.9 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.
 
Effect of Inflation
 
We do not expect that inflation will be a significant risk in the near term, given the current global economic conditions. However, that could change in the future. To address rising inflation, some of our contracts include certain mitigating factors against any inflation risk. In connection with the Electricity Segment, inflation may directly impact an expense incurred for the operation of our projects, hence increasing the overall operating cost to us. The negative impact of inflation may be partially offset by price adjustments built into some of our PPAs that could be triggered upon such occurrences. The energy payments pursuant to the PPAs for the Brady power plant, the Steamboat 2/3 power plant, the Steamboat Hills power plant, and the Burdette power plant increase every year through the end of the relevant terms of such agreements, though such increases are not directly linked to the CPI or any other inflationary index. Lease payments are generally fixed, while royalty payments are generally determined as a percentage of revenues and therefore are not significantly impacted by inflation. In our Product Segment, inflation may directly impact fixed and variable costs incurred in the construction of our power plants, hence


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increasing our operating costs in that segment. In this segment, it is more likely that we will be able to offset part or all of the inflationary impact through our project pricing. With respect to power plants that we construct for our own electricity production, inflationary pricing may impact our operating costs which may be partially offset in the pricing of the new long-term PPAs that we negotiate. Overall, we believe that the impact of inflation on our business will not be significant.
 
Contractual Obligations and Commercial Commitments
 
The following tables set forth our material contractual obligations as of December 31, 2010 (in thousands):
 
                                                         
    Payments Due By Period  
    Remaining
                                     
    Total     2011     2012     2013     2014     2015     Thereafter  
 
Long-term liabilities principal
  $ 789,669     $ 49,021     $ 243,753     $ 56,776     $ 59,896     $ 53,368     $ 326,855  
Interest on long-term liabilities(1)
    278,300       48,552       49,144       44,634       38,123       34,255       63,592  
Future minimum operating lease
    80,187       8,061       8,199       8,062       8,647       8,222       38,996  
Benefits upon retirement(2)
    15,913       3,792       1,197       889       600       795       8,640  
Asset retirement obligation
    19,903                                     19,903  
Purchase commitments(3)
    56,600       56,600                                
                                                         
    $ 1,240,572     $ 166,026     $ 302,293     $ 110,361     $ 107,266     $ 96,640     $ 457,986  
                                                         
 
 
(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 Loan due in 2011 is fixed at a rate of 11.775%. 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 Senior Unsecured Bonds due in 2017 is fixed at a rate of 7%. Interest on the remaining debt is variable (based primarily on changes in LIBOR rates).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.
 
(3) We purchase raw materials for inventories, construction-in-process and services from a variety of vendors. During the normal course of business, in order to manage manufacturing lead times and help assure adequate supply, we enter into agreements with contract manufacturers and suppliers that either allow them to procure goods and services based upon specifications defined by us, or that establish parameters defining our requirements. At December 31, 2010, total obligations related to such supplier agreements were approximately $56.6 million (out of which approximately $36.8 million relate to construction-in-process). All such obligations are payable in 2011.
 
The above table does not reflect unrecognized tax benefits of $5.4 million the timing of which is uncertain. Refer to Note 19 to our consolidated financial statements set forth in Item 8 of this annual report for additional discussion of unrecognized tax benefits. The above table also does not reflect a liability associated with the sale of tax benefits of $66.6 million the timing of which is uncertain. Refer to Note 13 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.


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Southern California Edison accounted for 29.1%, 21.1%, and 27.7% of our total revenues for the three years ended December 31, 2010, 2009, and 2008, respectively. Southern California Edison is also the power purchaser and revenue source for our Mammoth project, which we accounted for separately under the equity method of accounting through August 1, 2010.
 
Sierra Pacific Power Company and Nevada Power Company accounted for 15.0%, 13.0%, and 12.6% of our total revenues for the three years ended December 31, 2010, 2009, and 2008 and, respectively.
 
HELCO accounted for 8.6%, 6.3%, and 16.8% of our total revenues for the three years ended December 31, 2010, 2009, and 2008, 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 2010 was 2.2 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 place qualifying renewable energy facilities in service, during 2009, 2010 or 2011 or that begin construction of qualifying renewable energy facilities during 2009, 2010 or 2011 and place them in service by December 31, 2013, may choose to apply for a cash grant from the U.S. Treasury in an amount equal to the ITC. Under the ARRA, the U.S. Treasury is instructed to pay the cash grant within 60 days of the application or the date on which the qualifying facility is placed in service.
 
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.
 
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 arm’s length, and that the management and control of Ormat Systems will be from Israel during the whole period of the tax benefits. A change in control should be reported to the Israel Tax Authority in order to maintain the tax benefits. In January 2011, new legislation amending the Investment Law was enacted. Under the new legislation, a uniform rate of corporate tax would apply to all qualified income of certain industrial companies, as opposed to the current law’s incentives that are limited to


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income from a “Benefited Enterprise” during their benefits period. According to the amendment, the uniform tax rate applicable to the zone where the production facilities of Ormat Systems are located would be 15% in 2011 and 2012, 12.5% in 2013 and 2014, and 12% in 2015 and thereafter. Under the transitory provisions of the new legislation, Ormat Systems may opt whether to irrevocably implement the new law while waiving benefits provided under the current law or keep implementing the current law during the next years. Changing from the current law to the new law is permissible at any stage.
 
ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
Information responding to Item 7A is included in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, of this annual report.


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ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
Index to Consolidated Financial Statements of Ormat Technologies, Inc. and Subsidiaries
 
         
Report of Independent Registered Public Accounting Firm
    122  
Consolidated Financial Statements as of December 31, 2010 and 2009 and for Each of the Three Years in the Period Ended December 31, 2010:
       
Consolidated Balance Sheets
    123  
Consolidated Statements of Operations and Comprehensive Income
    124  
Consolidated Statements of Equity
    125  
Consolidated Statements of Cash Flows
    126  
Notes to Consolidated Financial Statements
    127  
 
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.


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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, equity and cash flows present fairly, in all material respects, the financial position of Ormat Technologies, Inc. and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 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, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
/s/  PricewaterhouseCoopers LLP
 
San Francisco, California
February 28, 2011


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
 
                 
    December 31,  
    2010     2009  
    (In thousands)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 82,815     $ 46,307  
Restricted cash, cash equivalents and marketable securities (all related to VIEs)
    23,309       40,955  
Receivables:
               
Trade
    54,495       53,423  
Related entity
    303       441  
Other
    8,173       7,884  
Due from Parent
    272       422  
Inventories
    12,538       15,486  
Costs and estimated earnings in excess of billings on uncompleted contracts
    6,146       14,640  
Deferred income taxes
    1,674       3,617  
Prepaid expenses and other
    14,929       12,080  
                 
Total current assets
    204,654       195,255  
Long-term marketable securities
    1,287       652  
Restricted cash, cash equivalents and marketable securities (all related to VIEs)
    1,740       2,512  
Unconsolidated investments
    4,244       35,188  
Deposits and other
    21,353       18,653  
Deferred income taxes
    17,087        
Deferred charges
    37,571       31,724  
Property, plant and equipment, net ($1,371,400 related to VIEs at December 31, 2010)
    1,425,467       998,693  
Construction-in-process ($149,851 related to VIEs at December 31, 2010)
    270,634       518,595  
Deferred financing and lease costs, net
    19,017       20,940  
Intangible assets, net
    40,274       41,981  
                 
Total assets
  $ 2,043,328     $ 1,864,193  
                 
 
LIABILITIES AND EQUITY
Current liabilities:
               
Accounts payable and accrued expenses
  $ 85,549     $ 73,993  
Billings in excess of costs and estimated earnings on uncompleted contracts
    3,153       3,351  
Current portion of long-term debt:
               
Limited and non-recourse (all related to VIEs at December 31, 2010)
    15,020       19,191  
Full recourse
    13,010       12,823  
Senior secured notes (non-recourse) (all related to VIEs at December 31, 2010)
    20,990       20,227  
Due to Parent, including current portion of notes payable to Parent
          10,018  
                 
Total current liabilities
    137,722       139,603  
Long-term debt, net of current portion:
               
Limited and non-recourse (all related to VIEs at December 31, 2010)
    114,132       129,152  
Full recourse:
               
Senior unsecured bonds
    142,003        
Other
    84,166       77,177  
Revolving credit lines with banks
    189,466       134,000  
Senior secured notes (non-recourse) (all related to VIEs at December 31, 2010)
    210,882       231,872  
Liability associated with sale of tax benefits
    66,587       73,246  
Deferred lease income
    71,264       72,867  
Deferred income taxes
    30,878       53,722  
Liability for unrecognized tax benefits
    5,431       4,931  
Liabilities for severance pay
    20,706       18,332  
Asset retirement obligation
    19,903       14,238  
Other long-term liabilities
    4,961       3,358  
                 
Total liabilities
    1,098,101       952,498  
                 
Commitments and contingencies
               
Equity:
               
The Company’s stockholders’ equity:
               
Common stock, par value $0.001 per share; 200,000,000 shares authorized; 45,430,886 shares issued and outstanding, respectively
    46       46  
Additional paid-in capital
    716,731       709,354  
Retained earnings
    221,311       196,950  
Accumulated other comprehensive income
    1,044       622  
                 
      939,132       906,972  
Noncontrolling interest
    6,095       4,723  
                 
Total equity
    945,227       911,695  
                 
Total liabilities and equity
  $ 2,043,328     $ 1,864,193  
                 
 
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,  
    2010     2009     2008  
    (In thousands, except per share data)  
 
Revenues:
                       
Electricity
  $ 291,820     $ 252,621     $ 251,373  
Product
    81,410       159,389       92,577  
                         
Total revenues
    373,230       412,010       343,950  
                         
Cost of revenues:
                       
Electricity
    242,326       179,101       169,297  
Product
    53,277       112,450       72,755  
                         
Total cost of revenues
    295,603       291,551       242,052  
                         
Gross margin
    77,627       120,459       101,898  
Operating expenses:
                       
Research and development expenses
    10,120       10,502       4,595  
Selling and marketing expenses
    13,447       14,584       10,885  
General and administrative expenses
    27,442       26,412       25,938  
Write-off of unsuccessful exploration activities
    3,050       2,367       9,828  
                         
Operating income
    23,568       66,594       50,652  
Other income (expense):
                       
Interest income
    343       639       3,118  
Interest expense, net
    (40,473 )     (16,241 )     (14,945 )
Foreign currency translation and transaction gains (losses)
    1,557       (1,695 )     (4,421 )
Impairment of auction rate securities
    (137 )     (279 )     (4,195 )
Income attributable to sale of tax benefits
    8,729       15,515       18,118  
Gain on acquisition of controlling interest
    36,928              
Gain from extinguishment of liability
          13,348        
Other non-operating income (expense), net
    267       479       771  
                         
Income from continuing operations, before income taxes and equity in income of investees
    30,782       78,360       49,098  
Income tax benefit (provision)
    1,098       (15,430 )     (5,310 )
Equity in income of investees, net
    998       2,136       1,725  
                         
Income from continuing operations
    32,878       65,066       45,513  
Discontinued operations:
                       
Income from discontinued operations, net of related tax of $6, $1,494 and ($952), respectively
    14       3,487       (2,221 )
Gain on sale of a subsidiary in New Zealand net of tax of $2,000
    4,336              
                         
Net income
    37,228       68,553       43,292  
Net loss attributable to noncontrolling interest
    90       298       316  
                         
Net income attributable to the Company’s stockholders
  $ 37,318     $ 68,851     $ 43,608  
                         
Comprehensive income:
                       
Net income
  $ 37,228     $ 68,553     $ 43,292  
Other comprehensive income (loss), net of related taxes:
                       
Currency translation adjustment
    43       842       (885 )
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge
    (234 )     (254 )     (293 )
Change in unrealized gains or losses on marketable securities available-for-sale
    (80 )     594       435  
                         
Comprehensive income
    36,957       69,735       42,549  
Comprehensive loss attributable to noncontrolling interest
    90       298       316  
                         
Comprehensive income attributable to the Company’s stockholders
  $ 37,047     $ 70,033     $ 42,865  
                         
Earnings per share attributable to the Company’s stockholders:
                       
Basic:
                       
Income from continuing operations
  $ 0.72     $ 1.44     $ 1.04  
Discontinued operations
    0.10       0.08       (0.05 )
                         
Net income
  $ 0.82     $ 1.52     $ 0.99  
                         
Diluted:
                       
Income from continuing operations
  $ 0.72     $ 1.43     $ 1.03  
Discontinued operations
    0.10       0.08       (0.05 )
                         
Net income
  $ 0.82     $ 1.51     $ 0.98  
                         
Weighted average number of shares used in computation of earnings per share attributable to the Company’s stockholders:
                       
Basic
    45,431       45,391       44,182  
                         
Diluted
    45,452       45,533       44,298  
                         
Dividend per share declared
  $ 0.27     $ 0.25     $ 0.20  
                         
 
The accompanying notes are an integral part of the consolidated financial statements.


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF EQUITY
 
                                                                 
    The Company’s Stockholders’ Equity              
                            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, 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 follow-on public offering
                                                             
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)
                      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)
                            (293 )     (293 )           (293 )
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $260)
                            435       435             435  
                                                                 
Balance at December 31, 2008
    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)
                      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  
Tax benefit on exercise of options by employees
                                               
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)
                            (254 )     (254 )           (254 )
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $339)
                                    594       594               594  
                                                                 
Balance at December 31, 2009
    45,431       46       709,354       196,950       622       906,972       4,723       911,695  
Stock-based compensation
                7,377                   7,377             7,377  
Cumulative effect of adopting the guidance on evaluation of credit derivatives embedded in beneficial interests in securitized financial assets as of July 1, 2010 (net of related tax of $370)
                      (693 )     693                    
Increase in noncontrolling interest due to acquisition
                                        1,462       1,462  
Cash dividend declared, $0.27 per share
                      (12,264 )           (12,264 )           (12,264 )
Net income (loss)
                      37,318             37,318       (90 )     37,228  
Other comprehensive income (loss), net of related taxes:
                                                               
Currency translation adjustment
                            43       43             43  
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $143)
                            (234 )     (234 )           (234 )
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $43)
                            (80 )     (80 )           (80 )
                                                                 
Balance at December 31, 2010
    45,431     $ 46     $ 716,731     $ 221,311     $ 1,044     $ 939,132     $ 6,095     $ 945,227  
                                                                 
 
The accompanying notes are an integral part of the consolidated financial statements.


125


 

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands)  
 
Cash flows from operating activities:
                       
Net income
  $ 37,228     $ 68,553     $ 43,292  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation and amortization
    86,761       64,376       60,128  
Accretion of asset retirement obligation
    1,249       1,060       1,069  
Stock-based compensation
    7,377       5,755       4,444  
Amortization of deferred lease income
    (2,685 )     (2,685 )     (2,685 )
Income attributable to sale of tax benefits, net of interest expense
    (3,523 )     (8,322 )     (10,850 )
Equity in income of investees
    (998 )     (2,136 )     (1,725 )
Impairment of auction rate securities
    137       279       4,195  
Loss on disposal of property, plant and equipment
    1,245       2,469        
Write-off of unsuccessful exploration activities
    3,050       2,367       9,828  
Loss from sale of auction rate securities
          194        
Return on investment in unconsolidated investments
    3,734             2,435  
Changes in unrealized loss in respect of derivative instruments, net
                 
Gain on severance pay fund asset
    (1,889 )     (468 )     (324 )
Gain from extinguishment of liability
          (13,348 )      
Gain on sale of a subsidiary
    (6,350 )            
Gain on acquisition of controlling interest
    (36,928 )              
Deferred income tax provision (benefit)
    (10,139 )     3,957       3,241  
Liability for unrecognized tax benefits
    500       1,506       (188 )
Deferred lease revenues
    1,082       1,125       914  
Other
                (423 )
Changes in operating assets and liabilities, net of amounts acquired:
                       
Receivables
    1,259       3,921       (6,327 )
Costs and estimated earnings in excess of billings on uncompleted contracts
    8,894       (7,658 )     (3,374 )
Inventories
    2,948       (1,762 )     (3,412 )
Prepaid expenses and other
    (2,595 )     4,146       (9,163 )
Deposits and other
    (164 )     (49 )     (224 )
Accounts payable and accrued expenses
    9,695       (2,081 )     13,521  
Due from/to related entities, net
    (89 )     (103 )     47  
Billings in excess of costs and estimated earnings on uncompleted contracts
    (198 )     (12,319 )     10,852  
Liabilities for severance pay
    2,610       692       2,439  
Other long-term liabilities
    (540 )            
Due from/to Parent
    (268 )     1,303       (761 )
                         
Net cash provided by operating activities
    101,403       110,772       116,949  
                         
Cash flows from investing activities:
                       
Return of investment in unconsolidated investments
    3,516             316  
Marketable securities, net
          1,580       12,594  
Net change in restricted cash, cash equivalents and marketable securities
    17,536       (15,873 )     5,614  
Cash received from sale of a subsidiary
    19,594                  
Capital expenditures
    (283,313 )     (270,623 )     (416,606 )
Cash grant received from the U.S. Treasury under Section 1603 of the ARRA
    108,286                
Investment in unconsolidated companies
    (2,715 )     (261 )      
Cash paid for acquisition of controlling interest in a subsidiary, net of cash acquired
    (64,517 )            
Cash paid for investment in a joint venture
    (100 )            
Intangible assets acquired
    (1,472 )            
Increase in severance pay fund asset, net of payments made to retired employees
    (635 )     (921 )     (1,034 )
Repayment from unconsolidated investment
          62       125  
                         
Net cash used in investing activities
    (203,820 )     (286,036 )     (398,991 )
                         
Cash flows from financing activities:
                       
Proceeds from public offerings, net of issuance costs
                149,655  
Proceeds from issuance of unregistered shares of common stock to the Parent
                33,315  
Proceeds from issuance of senior unsecured bonds
    142,003              
Proceeds from long-term loans
    20,000       237,000        
Proceeds from exercise of options by employees
          1,242       602  
Proceeds from the sale of limited liability company interest in OPC LLC, net of transaction costs
                63,029  
Payment for acquiring OPC LLC shares
          (18,500 )      
Purchase of OFC Senior Secured Notes
                (1,321 )
Proceeds from revolving credit lines with banks
    1,159,869       1,152,500       100,000  
Repayment of revolving credit lines with banks
    (1,104,403 )     (1,118,500 )      
Repayments of long-term debt
                       
Parent
    (9,600 )     (16,600 )     (31,647 )
Other
    (52,242 )     (33,193 )     (34,142 )
Cash paid to non-controlling interest
    (3,136 )            
Deferred debt issuance costs
    (1,302 )     (5,566 )     (1,293 )
Cash dividends paid
    (12,264 )     (11,347 )     (8,912 )
                         
Net cash provided by financing activities
    138,925       187,036       269,286  
                         
Effect of exchange rate changes on cash and cash equivalents
          142       (78 )
                         
Net change in cash and cash equivalents
    36,508       11,914       (12,834 )
Cash and cash equivalents at beginning of year
    46,307       34,393       47,227  
                         
Cash and cash equivalents at end of year
  $ 82,815     $ 46,307     $ 34,393  
                         
Supplemental disclosure of cash flow information:
                       
Cash paid during the year for:
                       
Interest, net of interest capitalized
  $ 34,587     $ 369     $ 6,220  
                         
Income taxes, net
  $ 7,570     $ 5,098     $ 5,033  
                         
Supplemental non-cash investing and financing activities:
                       
Increase (decrease) in accounts payable related to purchases of property, plant and equipment
  $ 507     $ (23,890 )   $ 13,368  
                         
Payable related to investment in joint venture
  $ 2,400     $     $  
                         
Increase (decrease) in asset retirement cost and asset retirement obligation
  $ 1,238     $ (260 )   $ (645 )
                         
Acquisitions — See Note 2
                       
 
The accompanying notes are an integral part of the consolidated financial statements.


126


 

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
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, and Nicaragua. The Company’s equipment manufacturing operations are located in Israel.
 
Most of the Company’s domestic power plant facilities are Qualifying Facilities under the Public Utility Regulatory Policies Act of 1978 (“PURPA”). The power purchase agreements (“PPAs”) for certain of such facilities are dependent upon their maintaining Qualifying Facility status. Management believes that all of the facilities were in compliance with Qualifying Facility status as of December 31, 2010.
 
Cash dividends
 
During the years ended December 31, 2010, 2009, and 2008, the Company’s Board of Directors declared, approved, and authorized the payment of cash dividends in the aggregate amount of $12.3 million ($0.27 per share), $11.3 million ($0.25 per share), and $8.9 million ($0.20 per share) respectively. Such dividends were paid in the years declared.
 
Issuance of stock and shelf registration statements
 
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.
 
On September 17, 2008, the Company filed a universal shelf registration statement on Form S-3, which was declared effective by the Securities and Exchange Commission (“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.


127


 

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Reclassification
 
Certain comparative figures have been reclassified to conform to the current year presentation (see Note 17).
 
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.
 
Marketable securities
 
At December 31, 2010 and 2009, 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 7.
 
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 7). 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, 2010 and 2009, the Company had deposits totaling $55,537,000 and $24,561,000, respectively, 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, 2010 and 2009, the Company’s deposits in foreign countries of approximately $37,929,000 and $35,095,000, respectively, were not insured.
 
At December 31, 2010 and 2009, accounts receivable related to operations in foreign countries amounted to approximately $26,128,000 and $30,761,000, respectively. At December 31, 2010 and 2009, accounts receivable


128


 

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
from the Company’s major customers that have generated 10% or more of its revenues (see Note 20) amounted to approximately 40% and 61%, respectively, of the Company’s accounts receivable.
 
Southern California Edison Company (“SCE”) accounted for 29.1%, 21.1%, and 27.6% of the Company’s total revenues for the years ended December 31, 2010, 2009, and 2008, respectively. SCE is also the power purchaser and revenue source for the Mammoth complex, which was accounted for separately under the equity method through August 1, 2010.
 
Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 15.0%, 13.0%, and 12.6% of the Company’s total revenues for the years ended December 31, 2010, 2009, and 2008, respectively.
 
Hawaii Electric Light Company accounted for 8.6%, 6.3%, and 16.8% of the Company’s total revenues for the years ended December 31, 2010, 2009, and 2008, 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, 2010 and 2009.
 
Deferred Charges
 
Deferred charges represent prepaid income taxes on intercompany sales. Such amounts are being amortized and included in income tax provision over the life of the related property, plant and equipment.
 
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, since the Company does not own the geothermal resource used by the plant. The geothermal power plant in Nicaragua is to be fully depreciated over the period that the plant is operated by the Company (see Note 8). The other assets are depreciated using the straight-line method over the following estimated useful lives of the assets:
 
     
Leasehold improvements
  15-20 years
Machinery and equipment — manufacturing and drilling
  10 years
Machinery and equipment — computers
  3-5 years
Office equipment — furniture and fixtures
  5-15 years
Office equipment — other
  5-10 years
Automobiles
  5-7 years


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 $9,493,000, $27,395,000, and $21,312,000 for the years ended December 31, 2010, 2009, and 2008, respectively.
 
Cash grant
 
On August 27, 2010, the Company was awarded a cash grant from the U.S. Department of Treasury (“U.S. Treasury”) for Specified Energy Property in Lieu of Tax Credits under Section 1603 of the American Recovery and Reinvestment Act of 2009 (“ARRA”) in the amount of $108.3 million relating to its North Brawley geothermal power plant. The plant’s estimated useful life is 30 years. The Company has recorded the cash grant as a reduction in the carrying value of the plant and is amortizing the grant as a reduction in depreciation expense over the plant’s estimated useful life. During the year ended December 31, 2010, amortization of the cash grant reduced depreciation expense by $1.4 million.
 
For federal income tax purposes, the tax basis of the plant is only reduced by 50 percent of the cash grant. To account for the tax effect of the difference between the tax and book basis of the plant, the Company has recorded a deferred tax asset of $33.8 million with a corresponding decrease in the carrying value of the plant. This reduction in the carrying value of the plant will be amortized as a reduction in depreciation expense over the plant’s estimated useful life. During the year ended December 31, 2010, amortization of this basis difference reduced depreciation expense by $0.4 million.
 
Exploration and development costs
 
The Company capitalizes costs incurred in connection with the exploration and development of geothermal resources once it acquires land rights to the potential geothermal resource. Prior to acquiring land rights, the Company makes an initial assessment that an economically feasible geothermal reservoir is probable on that land. The Company determines the economic feasibility of potential geothermal resources internally, with all available data and external assessments vetted through the exploration department and occasionally using outside service providers. Costs associated with the initial assessment are expensed and included in cost of electricity revenues in the consolidated statements of operations and comprehensive income. Such costs were immaterial during the years ended December 31, 2010, 2009, and 2008. 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” in 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” in 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


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.
 
Grants received from the U.S. Department of Energy are offset against the related exploration and development costs. Such grants amounted to $1,116,000, $0, and $0 for the years ended December 31, 2010, 2009, and 2008, respectively.
 
All exploration and development costs that are being capitalized, including the up-front bonus payments made to secure land leases, will be depreciated over their estimated useful lives when the related geothermal power plant is substantially complete and ready for use. A geothermal power plant is substantially complete and ready for use when electricity generation commences.
 
Asset retirement obligation
 
The Company records the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. The Company’s legal liabilities include plugging wells and post-closure costs of power producing sites. When a new liability for asset retirement obligations is recorded, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. At retirement, the obligation is settled for its recorded amount at a gain or loss.
 
Deferred financing and lease transaction costs
 
Deferred financing costs are amortized over the term of the related obligation using the effective interest method. Amortization of deferred financing costs is presented as interest expense in the consolidated statements of operations and comprehensive income. Accumulated amortization related to deferred financing costs amounted to $12,966,000 and $9,924,000 at December 31, 2010 and 2009, respectively. Amortization expense for the years ended December 31, 2010, 2009, and 2008 amounted to $3,042,000, $3,060,000, and $1,499,000, 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 12) in the amount of $4,172,000 are amortized using the straight-line method over the 23-year term of the lease. Amortization of deferred transaction costs is presented in cost of revenues in the consolidated statements of operations and comprehensive income. Accumulated amortization related to deferred lease costs amounted to $1,037,000 and $853,000 at December 31, 2010 and 2009, respectively. Amortization expense for each of the years ended December 31, 2010, 2009, and 2008 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.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.
 
Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated future net undiscounted cash flows expected to be generated by the asset. The significant assumptions that the Company uses in estimating its undiscounted future cash flows include: (i) projected generating capacity of the complex or power plant and rates to be received under the respective PPA(s); and (ii) projected operating expenses of the relevant complex or power plant. Estimates of future cash flows used to test recoverability of a long-lived asset under development also include cash flows associated with all future expenditures necessary to develop the asset.
 
If the assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. Management believes that no impairment exists for long-lived assets; however, estimates as to the recoverability of such assets may change based on revised circumstances (see Note 8).
 
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.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Foreign currency translation
 
The U.S. dollar is the functional currency for substantially all of the Company’s consolidated operations and those of its equity affiliates. For those entities, all gains and losses from currency translations are included in results of operations. For the subsidiary in New Zealand that was sold in January 2010, and which was using a functional currency other than the U.S. dollar, the cumulative translation effects were included in “accumulated other comprehensive income” 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 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,  
    2010     2009     2008  
    (Dollars in thousands)  
 
Energy and capacity
  $ 106,891     $ 95,484     $ 100,178  
Lease portion of energy and capacity
    182,244       154,452       148,510  
Lease income
    2,685       2,685       2,685  
                         
    $ 291,820     $ 252,621     $ 251,373  
                         
 
The components of cost of electricity revenues are as follows:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Dollars in thousands)  
 
Energy and capacity
  $ 128,465     $ 94,067     $ 94,235  
Lease portion of energy and capacity
    108,619       79,792       69,820  
Lease income
    5,242       5,242       5,242  
                         
    $ 242,326     $ 179,101     $ 169,297  
                         
 
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


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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, 2010, 2009, and 2008.
 
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 $704,000, $1,330,000, and $554,000 for the years ended December 31, 2010, 2009, and 2008, 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). The Company uses the simplified method in developing an estimate of the expected term of “plain vanilla” stock-based awards. 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.
 
Income taxes
 
Income taxes are accounted for using the asset and liability approach, which requires the recognition of taxes payable or refundable for the current year and deferred tax assets and liabilities for the future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. The measurement of current and deferred tax assets and liabilities are based on provisions of the enacted tax law. The effects of future changes in tax laws or rates are not anticipated. The Company accounts for investment tax credits and production tax credits as a reduction to income taxes in the year in which the credit arises. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that, based on available evidence, are not, more likely than not expected to be realized. 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 19).
 
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.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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,  
    2010     2009     2008  
    (In thousands)  
 
Weighted average number of shares used in computation of basic earnings per share
    45,431       45,391       44,182  
Add:
                       
Additional shares from the assumed exercise of employee stock options
    21       142       116  
                         
Weighted average number of shares used in computation of diluted earnings per share
    45,452       45,533       44,298  
                         
 
The number of stock-based awards that could potentially dilute future earnings per share and were not included in the computation of diluted earnings per share because to do so would have been anti-dilutive was 2,676,712, 1,161,870, and 875,648, respectively, for the years ended December 31, 2010, 2009, and 2008.
 
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.
 
New accounting pronouncements
 
New accounting pronouncements effective in the year ended December 31, 2010
 
Accounting for Transfers of Financial Assets
 
In June 2009, the Financial Accounting Standards Board (“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”). The adoption by the Company of this amendment on January 1, 2010 did not have any 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


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
exposure due to that involvement, as well as how its involvement with VIEs impacts the company’s financial statements. Finally, a company is required to disclose significant judgments and assumptions used to determine whether or not to consolidate a VIE. The Company adopted this amendment on January 1, 2010. The impact of the adoption of this amendment on the Company’s consolidated financial statements is disclosed in Note 6.
 
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 requires 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 update became 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 by the Company of the new guidance on January 1, 2010 did not have a material impact on the Company’s consolidated financial statements (see Note 7).
 
Scope Exception Related to Embedded Credit Derivatives
 
In March 2010, the FASB issued an accounting standards update that amends and clarifies the guidance on how entities should evaluate credit derivatives embedded in beneficial interests in securitized financial assets. The updated guidance eliminates the scope exception for bifurcation of embedded credit derivatives in interests in securitized financial assets unless they are created solely by subordination of one beneficial interest to another. The guidance is effective on the first day of the first fiscal quarter beginning after June 15, 2010 (July 1, 2010 for the Company). The effect of adopting this accounting standards update on July 1, 2010 is disclosed in Note 7.
 
New accounting pronouncements effective in future years
 
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 for allocating arrangement considerations. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements.
 
In April 2010, the FASB issued guidance for revenue recognition — milestone method, which provides guidance on the criteria that, should be met for determining whether the milestone method of revenue recognition is appropriate. A vendor can recognize consideration that is contingent upon achievement of a milestone in its entirety as revenue in the period in which the milestone is achieved only if the milestone meets all criteria to be considered substantive. A milestone should be considered substantive in its entirety. An individual milestone may not be bifurcated. The amendments in this update are effective on a prospective basis for milestones achieved in fiscal years, and interim periods within those years, beginning on or after June 15, 2010 (January 1, 2011 for the Company). The adoption of this guidance is not expected to have a material effect on the Company’s consolidated financial statements.


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Accounting for Share-Based Payments
 
In April 2010, the FASB issued an accounting standards update, which addresses the classification of an employee share-based payment award with an exercise price denominated in the currency of a market in which the underlying equity security trades. This update clarifies that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity should not classify such an award as a liability if it otherwise qualifies as equity. The amendments in this update are effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2010 (January 1, 2011 for the Company). The adoption of this update is not expected to have a material effect on the Company’s consolidated financial statements.
 
NOTE 2 — MAMMOTH COMPLEX ACQUISITION
 
On August 2, 2010, the Company acquired the remaining 50% interest in Mammoth-Pacific, L.P. (“Mammoth Pacific”), which owns the Mammoth complex located near the city of Mammoth, California, for a purchase price of $72.5 million in cash. The Company acquired the remaining interest in Mammoth Pacific to increase its geothermal power plant operations in the United States.
 
Prior to the acquisition, the Company had a 50% interest in Mammoth Pacific that was accounted for under the equity method of accounting. Following the acquisition, the Company became the sole owner of the Mammoth complex, as well as the sole owner of rights to over 10,000 acres of undeveloped federal lands.
 
As a result of the acquisition of the remaining 50% interest in Mammoth Pacific, the financial statements of Mammoth Pacific have been consolidated with the Company’s financial statements effective August 2, 2010. The acquisition-date fair value of the previously held 50% equity interest was $64.9 million, which takes into account a “control premium” of $7.6 million. In the year ended December 31, 2010, the Company recognized a pre-tax gain of $36.9 million, which is equal to the difference between the acquisition-date fair value of the previously held 50% equity interest in Mammoth Pacific and the acquisition-date carrying value of such investment. The gain is included in “gain on acquisition of controlling interest” in the consolidated statements of operations and comprehensive income.
 
The values of the assets acquired and liabilities assumed at the acquisition date are based management’s estimates using the methodology and assumptions described below.
 
Valuation methodology and assumptions
 
In estimating the fair value for the assets acquired, the Company primarily relied on the “Income Approach”. After reviewing several geothermal transactions, the Company concluded that those transactions were not sufficiently comparable to the assets acquired in this transaction. The Company also considered the “Cost Approach” as a reasonableness check to compare to the “Income Approach” value, but did not rely on it as a final indicator of the value.
 
The “Income Approach” is based on the premise that the value of an asset is equal to the present value of the cash flows that the assets are expected to generate. To estimate the fair value of the existing and replacement tangible and intangible assets as well as the development project at the Mammoth Pacific site, a discounted cash flow (“DCF”) analysis was utilized whereby the cash flows expected to be generated by the acquired assets were discounted to their present value equivalent using the rate of return that reflects the relative risk of each asset, as well as the time value of money. This return, known as the weighted average cost of capital (“WACC”), is an overall rate based upon the individual rates of return for invested capital (equity and interest-bearing debt), and was calculated by weighting the acquired return on interest-bearing debt and common equity capital in proportion to their estimated percentage in the expected capital structure. The estimates for the WACC, which ranged from 9.5% to 14.0%, developed in the valuation are for independent power producers and geothermal power producers.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following table summarizes the fair value of the assets acquired and liabilities assumed at the acquisition date:
 
         
    (Dollars in thousands)  
 
Assets:
       
Current assets:
       
Cash and cash equivalents
  $ 7,983  
Trade receivables
    3,239  
Prepaid expenses and other
    254  
Deposits and other
    622  
Property, plant and equipment, net (including construction- in-process)
    129,764  
         
Total identifiable assets acquired
    141,862  
         
Liabilities:
       
Current liabilities — accounts payable and accrued expenses
    (1,072 )
Asset retirement obligation
    (3,342 )
         
Total identifiable liabilities assumed
    (4,414 )
         
Total net assets acquired
  $ 137,448  
         
 
The acquired property, plant and equipment will be depreciated over their estimated useful lives.
 
The revenues of the Mammoth complex and the net loss of the Mammoth complex were $7,567,000 and $645,000, respectively, for the period from August 2, 2010 to December 31, 2010.
 
The following unaudited consolidated pro forma financial information for the years ended December 31, 2010 and 2009, assumes the Mammoth Pacific acquisition occurred as of January 1, 2009, after giving effect to certain adjustments, including the depreciation based on the adjustments to the fair market value of the property, plant and equipment acquired, and related income tax effects. The pro forma results have been prepared for comparative purposes only and are not necessarily indicative of the results of operations that may occur in the future or that would have occurred had the acquisition of Mammoth Pacific been effected on the dates indicated.
 
                 
    Year Ended December 31,  
    2010     2009  
    (Dollars in thousands, except per share data)  
 
Revenues
  $ 384,706     $ 431,851  
                 
Income from continuing operations
    8,954       67,144  
                 
Net income
    13,304       70,631  
Net loss attributable to noncontrolling interest
    90       298  
                 
Net income attributable to the Company’s stockholders
  $ 13,394     $ 70,929  
                 
Earnings per share attributable to the Company’s stockholders — diluted:
               
Income from continuing operations
  $ 0.20     $ 1.47  
Income from discontinued operations
    0.10       0.08  
                 
Net income
  $ 0.30     $ 1.55  
                 


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 3 — INVENTORIES
 
Inventories consist of the following:
 
                 
    December 31,  
    2010     2009  
    (Dollars in thousands)  
 
Raw materials and purchased parts for assembly
  $ 7,030     $ 7,322  
Self-manufactured assembly parts and finished products
    5,508       8,164  
                 
Total
  $ 12,538     $ 15,486  
                 
 
NOTE 4 — COST AND ESTIMATED EARNINGS ON UNCOMPLETED CONTRACTS
 
Cost and estimated earnings on uncompleted contracts consist of the following:
 
                 
    December 31,  
    2010     2009  
    (Dollars in thousands)  
 
Costs and estimated earnings incurred on uncompleted contracts
  $ 26,228     $ 121,292  
Less billings to date
    23,235       110,003  
                 
Total
  $ 2,993     $ 11,289  
                 
 
These amounts are included in the consolidated balance sheets under the following captions:
 
                 
    December 31,  
    2010     2009  
    (Dollars in thousands)  
 
Costs and estimated earnings in excess of billings on uncompleted contracts
  $ 6,146     $ 14,640  
Billings in excess of costs and estimated earnings on uncompleted contracts
    (3,153 )     (3,351 )
                 
Total
  $ 2,993     $ 11,289  
                 
 
The completion costs of the Company’s construction contracts are subject to estimation. Due to uncertainties inherent in the estimation process, it is reasonably possible that estimated contract earnings will be further revised in the near term.
 
NOTE 5 — UNCONSOLIDATED INVESTMENTS
 
Unconsolidated investments in power plant projects consist of the following:
 
                 
    December 31,  
    2010     2009  
    (Dollars in thousands)  
 
Mammoth
  $     $ 33,659  
Sarulla
    2,244       1,529  
W&M
    2,000        
                 
    $ 4,244     $ 35,188  
                 
 
The Mammoth Complex
 
Prior to August 2, 2010, the Company had a 50% interest in Mammoth Pacific, which owns the Mammoth complex. The Company’s 50% ownership interest in Mammoth Pacific was accounted for under the equity method


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
of accounting as the Company had the ability to exercise significant influence, but not control, over Mammoth Pacific. On August 2, 2010, the Company acquired the remaining 50% interest in Mammoth Pacific (see Note 2).
 
The unaudited condensed financial position and results of operations of Mammoth Pacific are summarized below:
 
         
    December 31, 2009
    (Dollars in thousands)
 
Condensed balance sheets:
       
Current assets
  $ 19,257  
Non-current assets
    64,728  
Current liabilities
    659  
Non-current liabilities
    3,196  
Partners’ capital
    80,130  
 
                         
    Period from
             
    January 1, 2010 to
    Year Ended December 31,  
    August 1, 2010     2009     2008  
    (Dollars in thousands)  
 
Condensed statements of operations:
                       
Revenues
  $ 11,484     $ 19,841     $ 19,175  
Gross margin
    2,670       6,181       5,180  
Net income
    2,528       5,993       4,868  
Company’s equity in income of Mammoth:
                       
50% of Mammoth net income
  $ 1,264     $ 2,997     $ 2,434  
Plus amortization of basis difference
    345       593       593  
                         
      1,609       3,590       3,027  
Less income taxes
    (611 )     (1,363 )     (1,149 )
                         
Total
  $ 998     $ 2,227     $ 1,878  
                         
 
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 energy sales contract, including an adjustment of commercial terms, and intends to proceed with the project after those amendments have become effective. On April 26, 2010, the parties agreed to increase the price of the power sold under the energy sales contract.
 
The Company’s investment in the Sarulla project was not significant for each of the years presented in these consolidated financial statements.
 
Watts & More Ltd.
 
In October 2010, the Company invested $2.0 million in Watts & More Ltd. (“W&M”), an early stage start-up company, engaged in the development of energy harvesting and system balancing solutions for electrical sources and, in particular, solar photovoltaic systems. The Company holds approximately 28.6% of W&M’s shares.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The Company’s investment in W&M was not significant for the year ended December 31, 2010.
 
NOTE 6 — VARIABLE INTEREST ENTITIES
 
Effective January 1, 2010, the Company adopted new accounting and disclosure guidance for variable interest entities (“VIEs”). Among other accounting and disclosure requirements, the new guidance requires the primary beneficiary of a VIE to be identified as the party that both (i) has the power to direct the activities of a VIE that most significantly impact its economic performance; and (ii) has an obligation to absorb losses or a right to receive benefits that could potentially be significant to the VIE. The adoption of this new accounting guidance did not result in the Company consolidating any additional VIEs or deconsolidating any VIEs.
 
The Company evaluated all transactions and relationships with VIEs to determine whether the Company is the primary beneficiary of the entities in accordance with the guidance. The Company’s overall methodology for evaluating transactions and relationships under the VIE requirements includes the following two steps: (i) determining whether the entity meets the criteria to qualify as a VIE; and (ii) determining whether the Company is the primary beneficiary of the VIE.
 
In performing the first step, the significant factors and judgments that the Company considers in making the determination as to whether an entity is a VIE include:
 
  •  The design of the entity, including the nature of its risks and the purpose for which the entity was created, to determine the variability that the entity was designed to create and distribute to its interest holders;
 
  •  The nature of the Company’s involvement with the entity;
 
  •  Whether control of the entity may be achieved through arrangements that do not involve voting equity;
 
  •  Whether there is sufficient equity investment at risk to finance the activities of the entity; and
 
  •  Whether parties other than the equity holders have the obligation to absorb expected losses or the right to receive residual returns.
 
If the Company identifies a VIE based on the above considerations, it then performs the second step and evaluates whether it is the primary beneficiary of the VIE by considering the following significant factors and judgments:
 
  •  Whether the Company has the power to direct the activities of the VIE that most significantly impact the entity’s economic performance; and
 
  •  Whether the Company has the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.
 
The Company’s VIEs include certain of its wholly owned subsidiaries that own one or more power plants with long-term PPAs. In most cases, the PPAs require the utility to purchase substantially all of the plant’s electrical output over a significant portion of its estimated useful life. Most of the VIEs have associated project financing debt that is non-recourse to the general creditors of the Company, is collateralized by substantially all of the assets of the VIE and those of its wholly owned subsidiaries (also VIEs) and is fully and unconditionally guaranteed by such subsidiaries. The Company has concluded that such entities are VIEs primarily because the entities do not have sufficient equity at risk and/or subordinated financial support is provided through the long-term PPAs. The Company has evaluated each of its VIEs to determine the primary beneficiary by considering the party that has the power to direct the most significant activities of the entity. Such activities include, among others, construction of the power plant, operations and maintenance, dispatch of electricity, financing and strategy. Except for power plants that it acquired, the Company is responsible for the construction of its power plants and generally provides operation and maintenance services. Primarily due to its involvement in these and other activities, the Company has concluded that it directs the most significant activities at each of its VIEs and, therefore, is considered the primary


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
beneficiary. The Company performs an ongoing reassessment of the VIEs to determine the primary beneficiary and may be required to deconsolidate certain of its VIEs in the future. The Company has aggregated its consolidated VIEs into the following categories: (i) wholly owned subsidiaries with project debt; (ii) wholly owned subsidiaries with PPAs; and (iii) less than majority-owned subsidiaries.
 
Agreement for joint development, construction, ownership and operation of one or more geothermal power plants in Oregon
 
On October 29, 2010, the Company entered into an agreement to jointly develop, construct, finance, own and operate one or more geothermal power plants in the Crump Geothermal Area located in Lake County, Oregon (the “Crump Project”). Under the terms of the agreement, the other joint owner, Nevada Geothermal Power Inc., contributed all of its rights, titles and interest in the Crump Project, consisting mainly of geothermal rights, to the newly formed entity. The Company paid $0.1 million and will pay an additional $2.4 million over a three-year period to the other joint owner for its ownership interest in the Crump Project and related rights. The Company has a 50% voting interest and will have equal representation with the other joint owner on the governing board. During the development stage of the Crump Project, the Company has the obligation to fund the first $15.0 million on behalf of the Crump Project. All other funding requirements will be required jointly by each owner. If the other joint owner is unable to obtain the necessary capital to fund its share of the Crump Project, the Company will provide financing directly to the joint owner in an aggregate amount of up to $15.0 million. In addition, the Company will be responsible for leading the development of the Crump Project and once operational, will be considered the operator of the facility. At any time during the development or construction of the Crump Project, the Company may terminate its involvement in the Crump Project, whereby the Company would transfer its 50% ownership interest to the other joint owner, at no cost to the other joint owner. If this occur, the Company will have no obligation to make any additional payments to the other joint owner.
 
The Company concluded that the entity is a VIE primarily because the entity does not have sufficient equity at risk. Through the Company’s equity ownership and other variable interest, the Company determined that it is the primary beneficiary of the Crump Project and therefore will consolidate the assets, liabilities and operations. In making the determination to consolidate, the Company considered the activities that most significantly impact the project’s economic performance, which party has the power to direct those activities, and whether the obligation to absorb the losses or the right to receive the benefits could potentially be significant to the Crump Project. The Company determined that the activities that most significantly impact the economic performance of the Crump Project currently include the development of the project. As the Company is the managing member and is primarily responsible during the development phase and further, since the Company’s obligations and benefits would be significant to the Crump Project, the Company determined that it is the primary beneficiary.
 
The Company has incurred $3.1 million in development costs of the Crump Project, as of December 31, 2010, which are presented in the Company’s consolidated balance sheet in “construction-in process”. No amounts related to this transaction have been included in the statement of operations and comprehensive income during the year ended December 31, 2010. In addition, the assets related to the Crump Project can only be used to settle the obligations related to the Crump Project.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The tables below detail the assets and liabilities (excluding intercompany balances which are eliminated in consolidation) for the Company’s VIEs, combined by VIE classifications, that were included in the consolidated balance sheets as of December 31, 2010 and 2009:
 
                         
    December 31, 2010  
                Less than Majority-
 
    Project Debt     PPAs     Owned Subsidiary  
    (Dollars in thousands)  
 
Assets:
                       
Restricted cash, cash equivalents and marketable securities
  $ 25,049     $     $  
Other current assets
    55,696       15,530        
Unconsolidated investments
                 
Property, plant and equipment, net
    933,560       437,840        
Construction-in-process
    113,937       29,985       5,929  
Other long-term assets
    52,484       270        
                         
Total assets
  $ 1,180,726     $ 483,625     $ 5,929  
                         
Liabilities:
                       
Accounts payable and accrued expenses
  $ 11,195     $ 4,533     $  
Long-term debt
    361,024              
Other long-term liabilities
    85,373       7,121        
                         
Total liabilities
  $ 457,592     $ 11,654     $  
                         
 
                 
    December 31, 2009  
    Project Debt     PPAs  
    (Dollars in thousands)  
 
Assets:
               
Restricted cash, cash equivalents and marketable securities
  $ 43,467     $  
Other current assets
    58,037       1,459  
Unconsolidated investments
    33,998        
Property, plant and equipment, net
    866,024       89,822  
Construction-in-process
    12,151       239,799  
Other long-term assets
    57,943        
                 
Total assets
  $ 1,071,620     $ 331,080  
                 
Liabilities:
               
Accounts payable and accrued expenses
  $ 11,328     $ 1,749  
Long-term debt
    400,442        
Other long-term liabilities
    87,181       3,198  
                 
Total liabilities
  $ 498,951     $ 4,947  
                 
 
NOTE 7 — FAIR VALUE OF FINANCIAL INSTRUMENTS
 
The fair value measurement guidance clarifies that fair value is an exit price, representing the amount that would be received 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


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under the fair value measurement guidance are described below:
 
Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities;
 
Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability;
 
Level 3 — Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (supported by little or no market activity).
 
The following table sets forth certain fair value information at December 31, 2010 and 2009 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, 2010  
    2010     Total     Level 1     Level 2     Level 3  
          (Dollars in thousands)              
 
Assets
                                       
Current assets:
                                       
Cash equivalents (including
                                       
restricted cash accounts)
  $ 14,370     $ 14,370     $ 14,370     $     $  
Derivatives(1)
          1,030             1,030        
Non-current assets:
                                       
Illiquid auction rate securities
                                       
including restricted cash
                                       
accounts) ($4.5 million par
                                       
value), see below(2)
    4,011       3,027                   3,027  
                                         
    $ 18,381     $ 18,427     $ 14,370     $ 1,030     $ 3,027  
                                         
 


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                         
    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  
                                         
 
 
(1) Derivatives represent foreign currency forward contracts which are valued primarily based on observable inputs including forward and spot prices for currencies.
 
(2) Included in the consolidated balance sheets as follows:
 
                 
    December 31,  
    2010     2009  
    (Dollars in thousands)  
 
Long-term marketable securities
  $ 1,287     $ 652  
Long-term restricted cash, cash equivalents
               
and marketable securities
    1,740       2,512  
                 
    $ 3,027     $ 3,164  
                 
 
The Company’s financial assets measured at fair value (including restricted cash accounts) at December 31, 2010 and 2009 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, 2010 and 2009, all of the Company’s auction rate securities are associated with failed auctions. Such securities have par values totaling $4.5 million at December 31, 2010 and 2009, 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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, 2010, 2009 and 2008:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Dollars in thousands)  
 
Balance at beginning of year
  $ 3,164     $ 4,945     $ 8,367  
Sale of auction rate securities
          (2,005 )      
Total unrealized gains (losses):
                       
Included in net income
    (137 )     (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
  $ 3,027     $ 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 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 $1,205,000 (net of taxes of $650,000) 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 related to auction rate securities for which the Company did not have the intent to sell and would not, more likely than not, be required to sell prior to recovery of its cost basis.
 
Effective July 1, 2010, the Company adopted an accounting standards update that amends and clarifies the guidance on how entities should evaluate credit derivatives embedded in beneficial interests in securitized financial assets. The updated guidance eliminates the scope exception for bifurcation of embedded credit derivatives in interests in securitized financial assets unless they are created solely by subordination of one beneficial interest to another. The auction rate securities held by the Company are considered securitized financial assets and therefore fall under the guideline in the abovementioned accounting standards update. The Company elected the fair value option for its auction rate securities as permitted by the update. Upon adoption of this accounting standards update, the Company reclassified $693,000 (net of income taxes of $377,000) to retained earnings with an offset to other comprehensive income. Effective with the adoption of this new guidance, all changes in the fair value of auction rate securities are recognized in earnings.
 
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


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
maturity. As a result, the Company has classified those securities with failed auctions as long-term assets in the consolidated balance sheets as of December 31, 2010 and 2009.
 
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 2011.
 
There were no transfers of assets or liabilities between Level 1 and Level 2 during the year ended December 31, 2010.
 
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,
    2010   2009   2010   2009
    (Dollars in millions)   (Dollars in millions)
 
Orzunil Senior Loans
  $ 1.7     $ 5.3     $ 1.7     $ 5.2  
Olkaria III Loan
    88.7       96.6       88.4       99.5  
Amatitlan Loan
    39.5       41.1       39.0       41.1  
Senior Secured Notes:
                               
Ormat Funding Corp.(“OFC”)
    129.5       132.0       136.3       146.3  
OrCal Geothermal Inc.(“OrCal”)
    93.5       103.7       95.6       105.8  
Senior unsecured bonds
    144.8             142.0        
Loans from institutional investors
    37.1       20.0       37.2       20.0  
Parent Loan
          9.7             9.6  
 
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.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 8 — PROPERTY, PLANT AND EQUIPMENT AND CONSTRUCTION-IN-PROCESS
 
Property, plant and equipment
 
Property, plant and equipment, net, consist of the following:
 
                 
    December 31,  
    2010     2009  
    (Dollars in thousands)  
 
Land owned by the Company where the geothermal resource is located
  $ 25,812     $ 25,507  
Leasehold improvements
    1,190       1,086  
Machinery and equipment
    73,745       64,725  
Office equipment
    14,979       13,075  
Automobiles
    5,283       4,679  
Geothermal and recovered energy generation power plants, including geothermal wells and exploration and resource development costs:
               
United States of America
    1,379,565       910,793  
Foreign countries
    280,525       254,849  
Asset retirement cost
    9,562       8,474  
                 
      1,790,661       1,283,188  
Less accumulated depreciation
    (365,194 )     (284,495 )
                 
Property, plant and equipment, net
  $ 1,425,467     $ 998,693  
                 
 
Depreciation expense for the years ended December 31, 2010, 2009, and 2008 amounted to $80,669,000, $60,811,000, and $51,873,000, respectively. Depreciation expense for the years ended December 31, 2010 is net at $1,382,000 impact of a cash grant received in August 2010 (see Note 1).
 
U.S. Operations
 
The net book value of the property, plant and equipment, including construction-in-process, located in the United States was approximately $,1,485,527,000 and $1,287,836,000 as of December 31, 2010 and 2009, respectively. This amount as of December 31, 2010 is net of a cash grant in the amount of $106,900,000 received on August 27, 2010 (net of accumulated depreciation of $1,382,000).
 
The North Brawley power plant (North Brawley) which is under development was tested for impairment in the current year due to the low output and higher than expected operating costs. Based on these indicators, the Company tested North Brawley for recoverability by estimating its future cash flows taking into consideration the various outcomes from different generating capacities, rates to be received under the PPA through the end of its term and expected market rates thereafter, possible penalties for underperformance during periods when the plant is expected to operate below the stated capacity in the PPA, projected capital expenditures to complete development of the plant and projected operating expenses over the life of the plant. The Company applied a probability-weighted approach and considered alternative courses of action.
 
Using a probability-weighted approach, the estimated undiscounted cash flows exceed the carrying value of the plant ($245 million as of December 31, 2010) by approximately $46 million and therefore, no impairment occurred. Estimated undiscounted cash flows are subject to significant uncertainties. If actual cash flows differ from the Company’s current estimates due to factors that include, among others, if the plant’s generating capacity is less than approximately 45 MW, or if the capital expenditures required to complete development of the plant and/or future operating costs exceed the level of our current projections, a material impairment write-down may be required in the future.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Foreign Operations
 
The net book value of property, plant and equipment, including construction-in-process, located outside of the United States was approximately $210,574,000 and $229,452,000 as of December 31, 2010 and 2009, 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 $111,112,000 and $110,810,000 as of December 31, 2010 and 2009, 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 $10,509,000 and $14,216,000 at December 31, 2010 and 2009, respectively.
 
The Company, through its wholly owned subsidiary, Orzunil I de Electricidad, Limitada (“Orzunil”), owns a power plant in Guatemala. The geothermal resources used by the power plant are owned by Instituto Nacional de Elecrification (“INDE”), a Guatemalan power utility, who granted the use of these resources to Orzunil for the period of the PPA. The net book value of the assets related to the power plant was $27,836,000 and $30,776,000 at December 31, 2010 and 2009, 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 $46,995,000 and $48,623,000 at December 31, 2010 and 2009, 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 at December 31, 2009. The former shareholder of GDL exercised its call option to purchase from the Company its shares in GDL in January 2010 (see Note 17).
 
Construction-in-process
 
Construction-in-process consists of the following:
 
                 
    December 31,  
    2010     2009  
    (Dollars in thousands)  
 
Projects under exploration and development:
               
Up-front bonus lease costs
  $ 33,600     $ 15,867  
Exploration and development costs
    20,997       17,698  
Interest capitalized
    100       52  
                 
      54,697       33,617  
                 
Projects under construction:
               
Up-front bonus lease costs
    31,179       3,179  
Drilling and construction costs
    176,968       442,218  
Interest capitalized
    7,790       39,581  
                 
      215,937       484,978  
                 
Total
  $ 270,634     $ 518,595  
                 


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following tables present a rollforward of the construction-in-process for the years ended December 31, 2010, 2009, and 2008:
 
                                 
    Projects Under Exploration and Development  
    Up-Front Bonus
    Exploration and
    Interest
       
    Lease Costs     Development Costs     Capitalized     Total  
    (Dollars in thousands)  
 
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
    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  
Cost incurred during the year
    17,733       21,483       158       39,374  
Write off of unsuccessful exploration costs
          (2,940 )     (110 )     (3,050 )
Transfer of projects under exploration and development to projects under construction
          (15,244 )           (15,244 )
                                 
Balance at December 31, 2010
  $ 33,600     $ 20,997     $ 100     $ 54,697  
                                 
 


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                 
    Projects Under Construction  
    Up-Front Bonus
    Drilling and
             
    Lease Costs     Construction Costs     Interest Capitalized     Total  
    (Dollars in thousands)  
 
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
          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  
Cost incurred during the year
    28,000       249,072       9,335       286,407  
Transfer of completed projects to property, plant and equipment
          (529,566 )     (41,126 )     (570,692 )
Transfer from projects under exploration and development
          15,244             15,244  
                                 
Balance at December 31, 2010
  $ 31,179     $ 176,968     $ 7,790     $ 215,937  
                                 
 
NOTE 9 — INTANGIBLE ASSETS
 
Intangible assets consist mainly of the Company’s PPAs acquired in business combinations and amounted to $40,274,000 and $41,981,000, net of accumulated amortization of $22,086,000 and $18,907,000, as of December 31, 2010 and 2009, respectively. Amortization expense for the years ended December 31, 2010, 2009, and 2008 amounted to $3,179,000, $3,197,000, and $3,136,000, respectively.
 
Estimated future amortization expense for the intangible assets as of December 31, 2010 is as follows:
 
         
    (Dollars in thousands)
 
Year ending December 31:
       
2011
  $ 3,236  
2012
    3,236  
2013
    3,236  
2014
    3,236  
2015
    3,236  
Thereafter
    24,094  
         
Total
  $ 40,274  
         

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 10 — ACCOUNTS PAYABLE AND ACCRUED EXPENSES
 
Accounts payable and accrued expenses consist of the following:
 
                 
    December 31,  
    2010     2009  
    (Dollars in thousands)  
 
Trade payables
  $ 51,915     $ 46,410  
Salaries and other payroll costs
    10,519       10,441  
Customer advances
    2,903       6,511  
Accrued interest
    6,383       2,061  
Income tax payable
    5,305       2,589  
Property tax
    2,960       1,629  
Scheduling and transmission
    1,376       871  
Royalty
    1,058       703  
Other
    3,130       2,778  
                 
Total
  $ 85,549     $ 73,993  
                 


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 11 — LONG-TERM DEBT AND CREDIT AGREEMENTS
 
Long-term debt consists of notes payable under the following agreements:
 
                 
    December 31,  
    2010     2009  
    (Dollars in thousands)  
 
Limited and non-recourse agreements:
               
Non-recourse agreement:
               
Senior loans (the Zunil power plant)
  $ 1,713     $ 5,225  
Loan agreement (the Olkaria III power plant)
    88,420       99,474  
Loan agreement (the Amatitlan power plant)
    39,019       41,056  
Limited recourse agreement:
               
Credit facility agreement
          2,588  
                 
      129,152       148,343  
Less current portion
    (15,020 )     (19,191 )
                 
Non current portion
  $ 114,132     $ 129,152  
                 
Full recourse agreements:
               
Senior unsecured bonds
  $ 142,003     $  
Loans from institutional investors
    57,176       40,000  
Loan from a commercial bank
    40,000       50,000  
                 
      239,179       90,000  
Less current portion
    (13,010 )     (12,823 )
                 
Non current portion
  $ 226,169     $ 77,177  
                 
Revolving credit lines with banks
  $ 189,466     $ 116,464  
                 
Senior Secured Notes (non-recourse):
               
Ormat Funding Corp. (“OFC”)
  $ 136,312     $ 146,323  
OrCal Geothermal Inc. (“OrCal”)
    95,560       105,776  
                 
Total
    231,872       252,099  
Less current portion
    (20,990 )     (20,227 )
                 
Non current portion
  $ 210,882     $ 231,872  
                 
 
Senior Loan (the Zunil Power Plant)
 
Orzunil, a wholly owned subsidiary of the Company, has a senior loan agreement with International Finance Corporation (“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%.
 
There are various restrictive covenants under this senior loan, which include limitations on Orzunil’s ability to make distributions to its shareholders. Management believes that as of December 31, 2010, Orzunil was in compliance with the covenants under this senior loan.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 6.9% 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, 2010, 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 in the consolidated balance sheet. As of December 31, 2010, the balance of such account was $10.5 million. In addition, as of December 31, 2010 and 2009, part of the restricted cash accounts were funded by a letter of credit in the amount of $5.9 million for both years.
 
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, 2010, 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 in the consolidated balance sheet. As of December 31, 2010 and 2009, the balance of such account was $2.0 million and $4.5 million, respectively.
 
Credit Facility Agreement (the Momotombo Power Plant)
 
Ormat Momotombo Power Company, a wholly owned subsidiary of the Company, entered into a credit facility agreement with Bank Hapoalim B.M. The loans under the credit facility agreement were fully repaid during the year ended December 31, 2010.


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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, 81/4% 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. Management believes that as of December 31, 2010, 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 in the consolidated balance sheet. As of December 31, 2010 and 2009, the balance of such account was $1.4 million and $0.1 million, respectively. In addition, as of December 31, 2010 and 2009, part of the restricted cash accounts was funded by a letter of credit in the amount of approximately $11.1 million (see Note 23).
 
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 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, 2010, 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.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Debt service reserve
 
As required under the terms of the OrCal Senior Secured Notes, OrCal maintains an account which may be funded by cash or backed by letters of credit (see below) in an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the OrCal Senior Secured Notes in the following six months. This restricted cash account is classified as current in the consolidated balance sheet. As of December 31, 2010 and 2009, the balance of such account was $0.3 million and $2.6 million, respectively. In addition, as of December 31, 2010 and 2009, part of the restricted cash accounts was funded by a letter of credit in the amount of $10.8 million and $11.3 million, respectively. (see Note 23).
 
Senior Unsecured Bonds
 
On August 3, 2010, the Company entered into a trust instrument governing the issuance of, and accepted subscriptions for, an aggregate principal amount of approximately $142.0 million of senior unsecured bonds (the “Bonds”). The Company issued the Bonds outside the United States to investors who are not “U.S. persons” in an unregistered offering pursuant to, and subject to the requirements of, Regulation S under the Securities Act of 1933, as amended.
 
Subject to early redemption, the principal of the Bonds is repayable in a single bullet payment upon the final maturity of the Bonds on August 1, 2017. The Bonds bear interest at a fixed rate of 7% per annum, payable semi-annually.
 
In February 2011, the Company accepted subscription for, an aggregate principal amount of approximately $108.0 million of additional senior unsecured bonds (the “Additional Bonds”) under two addendums to the trust instrument. The Company issued the Additional Bonds outside the United States to investors who are not “U.S. persons” in an unregistered offering pursuant to, and subject to the requirements of, Regulation S under the Securities Act of 1933, as amended. The terms and conditions of the Additional Bonds are identical to the original Bonds. The Additional Bonds were issued at a premium which reflects an effective fixed interest of 6.75% per annum.
 
Loans from institutional investors
 
In July 2009, the Company entered into a 6-year loan agreement of $20.0 million with a group of institutional investors (the “First Loan”). The First Loan matures on July 16, 2015, is payable in 12 semi-annual installments commencing January 16, 2010, and bears annual interest of 6.5%.
 
In July 2009, the Company entered into an 8-year loan agreement of $20.0 million with another group of institutional investors (the “Second Loan”). The Second Loan matures on August 1, 2017, is payable in 12 semi-annual installments commencing February 1, 2012, and bears interest at 6-month LIBOR plus 5.0%.
 
In November 2010, the Company entered into a 6-year loan agreement of $20.0 million with a group of institutional investors (the “Third Loan”). The Third Loan matures on November 16, 2016, is payable in ten semi-annual installments commencing May 16, 2012, and bears annual interest of 5.75%.
 
Loan from a commercial bank
 
On November 4, 2009, the Company entered into a 5-year loan agreement of $50.0 million with a commercial bank. The bank loan matures on November 10, 2014 and is payable in 10 semi-annual installments commencing May 10, 2010, and bears interest at 6-month LIBOR plus 3.25%.
 
Revolving credit lines with commercial banks
 
As of December 31, 2010, the Company has credit agreements with five commercial banks for an aggregate amount of $365.0 million. Under the terms of these credit agreements, the Company, or its Israeli subsidiary, Ormat


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Systems, can request: (i) extensions of credit in the form of loans and/or the issuance of one or more letters of credit in the amount of up to $315.0 million; and (ii) the issuance of one or more letters of credit in the amount of up to $50.0 million. The credit agreements mature between May 2011 and September 2013. 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, 2010, loans in the total amount of $189.5 million were outstanding, and letters of credit with an aggregate stated amount of $29.5 million were issued and outstanding under such credit agreements. The $189.5 million in loans are for terms of three months or less, The Company intends to replace them with new draw-downs from the same or other lines of credit and with the proceeds from the issuance of the Additional Bonds in February 2011 (see above), therefore such amounts are classified as long-term debt. The loans bear interest at an annual weighted average rate of 2.03% as of December 31, 2010.
 
Restrictive covenants
 
Under the credit agreements, the loan agreements, and the trust instrument governing the Bonds, described above, are unsecured, but the Company is subject to a negative pledge in favor of the banks and the other lenders and certain other restrictive covenants. These include, among other things, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of their assets, or a change of control in the Company’s ownership structure. Some of the credit agreements, the loan agreements, and the trust instrument contain cross-default provisions with respect to other material indebtedness owed by us to any third party. In some cases, the Company agreed to maintain certain financial ratios such as a debt to equity ratio, and a debt to adjusted EBITDA ratio. There are also certain restrictions on distribution of dividends. 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, 2010, the Company was in compliance with the covenants under the credit agreements, the loan agreements and the trust instrument.
 
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 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, 2010, the Company was in compliance with the covenants under the credit agreement. As of December 31, 2010, thirteen letters of credit with an aggregated stated amount of $34.4 million were issued and outstanding under the credit agreement.


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Future minimum payments
 
Future minimum payments under long-term obligations, excluding revolving credit lines with commercial banks, as of December 31, 2010 are as follows:
 
         
    (Dollars in thousands)  
 
Year ending December 31:
       
2011
  $ 49,021  
2012
    54,287  
2013
    56,776  
2014
    59,896  
2015
    53,368  
Thereafter
    326,855  
         
Total
  $ 600,203  
         
 
NOTE 12 — PUNA POWER PLANT LEASE TRANSACTIONS
 
In 2005, the Company’s wholly owned subsidiary in Hawaii, Puna Geothermal Ventures (“PGV”), entered into transactions involving the 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, 2010 and 2009 amounted to $45.1 million and $47.8 million, net of accumulated depreciation of $17.3 million and $14.6 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, 2010, are as follows:
 
         
    (Dollars in thousands)  
 
Year ending December 31:
       
2011
  $ 8,061  
2012
    8,199  
2013
    8,062  
2014
    8,647  
2015
    8,222  
Thereafter
    38,996  
         
Total
  $ 80,187  
         


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 $8.1 million and $11.7 million as of December 31, 2010 and 2009, respectively, and were included in restricted cash accounts in the consolidated balance sheets. As of December 31, 2010 and 2009, $1.7 million and $2.5 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 7, and the remaining $6.4 million and $9.2 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 the Company’s wholly owned subsidiary, 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, 2010 and 2009, the balance of such account was $0 and $0.7 million respectively. This amount can be distributed to Ormat Nevada currently and has been classified as current restricted assets.
 
NOTE 13 — OPC TRANSACTION
 
In June 2007, Ormat Nevada entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. ( Morgan Stanley Geothermal LLC and Lehman-OPC LLC), under which those investors purchased, for cash, interests in a newly formed subsidiary of Ormat Nevada, OPC LLC (“OPC”), entitling the investors to certain tax benefits (such as production tax credits and accelerated depreciation) and distributable cash associated with four geothermal power plants.
 
The first closing under the agreements occurred in 2007 and covered the Company’s Desert Peak 2, Steamboat Hills, and Galena 2 power plants. The investors paid $71.8 million at the first closing. The second closing under the agreements occurred in 2008 and covered the Galena 3 power plant. The investors paid $63.0 million at the second closing.
 
Ormat Nevada continues to operate and maintain the power plants. Under the agreements, Ormat Nevada initially received all of the distributable cash flow generated by the power plants until it recovered the capital that it has invested in the power plants, which occurred in the fourth quarter of 2010, while the investors receive substantially all of the production tax credits and the taxable income or loss (together, the “Economic Benefits”), and receive the distributable cash flow after Ormat Nevada 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 and is not subject to mandatory redemption or guaranteed payments. Cash is distributed each period in accordance with the cash allocation percentages stipulated in the agreements. Until the fourth quarter of 2010, Ormat Nevada was allocated the cash earnings in OPC and therefore, the amount allocated to the 5% residual interest represented the noncash loss of OPC which principally represented depreciation on the property, plant and equipment. As from the fourth quarter of 2010, the distributable cash is allocated


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
to the Class B membership units. As a result of the acquisition by Ormat Nevada, on October 30, 2009, of all of the Class B membership units of OPC held by Lehman-OPC LLC (see below), the residual interest decreased to 3.5%. Such residual interest increased to 5% on February 3, 2011 when Ormat Nevada sold it Class B membership units to JPM Capital Corporation (“JPM”) (see below).
 
The Company’s voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. The Company owned, 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 from October 30, 2009 to February 3, 2011. In total the Company had 82.5% of the voting rights in OPC as of December 31, 2010. The investors owned 70% of the Class B membership units, which represented 17.5% of the voting rights of OPC, as of December 31, 2010. 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 95% and the investor’s voting rights will decrease to 5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the Flip Date and therefore has continued to consolidate OPC.
 
On October 30, 2009, Ormat Nevada acquired from Lehman-OPC all of the Class B membership units of OPC held by 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 year ended December 31, 2009. In addition, an amount of approximately $1.1 million has been reclassified from noncontrolling interest to additional paid-in capital representing the 1.5% residual interest of Lehman-OPC LLC’s Class B membership units. As a result of that transaction, Lehman-OPC LLC has no further interest in OPC.
 
On February 3, 2011, Ormat Nevada sold to JPM all of the Class B membership units of OPC that it had acquired on October 30, 2010 for a sale price of $24.9 million in cash. The Company will not record any gain from the sale of its Class B membership interests in OPC to JPM.
 
NOTE 14 — ASSET RETIREMENT OBLIGATION
 
The following table presents a reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligation for the years presented below:
 
                 
    Year Ended December 31,  
    2010     2009  
    (Dollars in thousands)  
 
Balance at beginning of year
  $ 14,238     $ 13,438  
Liability associated with acquisition of controlling interest in a subsidiary
    3,342        
Changes in price estimates
    527       (686 )
Liabilities incurred
    547       426  
Accretion expense
    1,249       1,060  
                 
Balance at end of year
  $ 19,903     $ 14,238  
                 
 
During the year ended December 31, 2010, the Company increased the aggregate carrying amount of its asset retirement obligation by $527,000 due to increased costs associated with demolition and abandonment of property, plant and equipment. 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 property, plant and equipment.


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 15 — STOCK-BASED COMPENSATION
 
The Company makes an estimate of expected forfeitures and recognizes compensation costs only for those stock-based awards expected to vest. As of December 31, 2010, the total future compensation cost related to unvested stock-based awards that are expected to vest is $9,657,000, which amount will be recognized over a weighted average period of 1.3 years.
 
During the years ended December 31, 2010, 2009 and 2008, the Company recorded compensation related to stock-based awards as follows:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Dollars in thousands, except
 
    per share data)  
 
Cost of revenues
  $ 4,403     $ 3,296     $ 2,471  
Selling and marketing expenses
    780       708       221  
General and administrative expenses
    2,195       1,751       1,752  
                         
Total stock-based compensation expense
    7,378       5,755       4,444  
Tax effect on stock-based compensation expense
    924       701       483  
                         
Net effect of stock-based compensation expense
  $ 6,454     $ 5,054     $ 3,961  
                         
Effect of stock-based compensation expense on earnings per share
  $ 0.14     $ 0.11     $ 0.09  
                         
 
During the fourth quarter of 2010, the Company evaluated the trends in the stock-based award forfeiture rate and came to the conclusion that the actual rate is 5.7%. This change resulted in an increase in the stock-based award expenses of approximately $1.0 million.
 
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 0.72% yearly weighted average dividend rate in the year ended December 31, 2010. The risk-free interest rate was based on the yield from U.S. constant treasury maturities bonds with an equivalent term. The forfeiture rate is based on trends in actual stock-based awards forfeitures.
 
The Company calculated the fair value of each stock-based award on the date of grant based on the following assumptions:
 
                         
    Year Ended December 31,
    2010   2009   2008
 
For stock options issued by the Company:
                       
Risk-free interest rates
    2.5 %     1.6 %     2.7 %
Expected lives (in years)
    5.1       5.1       5.0  
Dividend yield
    0.72 %     0.38 %     0.37 %
Expected volatility
    47.6 %     48.6 %     38.5 %
Forfeiture rate
    13.0 %     13.0 %     13.0 %


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Stock-based awards
 
The 2004 Incentive Compensation Plan
 
In 2004, the Company’s Board of Directors adopted the 2004 Incentive Compensation Plan (“2004 Incentive Plan”), which provides for the grant of the following types of awards: incentive stock options, non-qualified stock options, restricted stock, stock appreciation rights (“SARs”), stock units, performance awards, phantom stock, incentive bonuses, and other possible related dividend equivalents to employees of the Company, directors and independent contractors. Under the 2004 Incentive Plan, a total of 3,750,000 shares of the Company’s common stock have been reserved for issuance, all of which could be issued as options or as other forms of awards. Options and SARs granted to employees under the 2004 Incentive Plan cliff vest and are exercisable from the grant date as follows: 25% after 24 months, 25% after 36 months, and the remaining 50% after 48 months. Options granted to non-employee directors under the 2004 Incentive Plan cliff vest and are exercisable one year after the grant date. Vested shares may be exercised for up to ten years from the date of grant. The shares of common stock will be issued upon exercise of options or SARs from the Company’s authorized share capital.
 
The 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,  
    2010     2009     2008  
          Weighted
          Weighted
          Weighted
 
          Average
          Average
          Average
 
          Exercise
          Exercise
          Exercise
 
    Shares     Price     Shares     Price     Shares     Price  
 
Outstanding at beginning of year
    1,745     $ 36.08       1,233     $ 39.14       817     $ 35.38  
Granted, at fair value:
                                               
Stock Options
    37       28.39       30       38.50       481       44.53  
SARs*
    592       29.95       573       26.84                  
Exercised
                (79 )     15.96       (29 )     11.36  
Forfeited
    (39 )     38.96       (12 )     44.20       (36 )     40.01  
                                                 
Outstanding at end of year
    2,335       34.35       1,745       36.08       1,233       39.14  
                                                 
Options exercisable at end of year
    621       37.65       331       35.23       230       27.61  
                                                 
Weighted-average fair value of options granted during the year
          $ 12.51             $ 11.63             $ 16.48  
                                                 
 
 
* 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, 2010, 1,239,699 shares of the Company’s common stock are available for future grants.


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following table summarizes information about stock-based awards outstanding at December 31, 2010 (shares in thousands):
 
                                                     
    Options Outstanding   Options 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   Exerciseble   Years   Intrinsic Value
            (Dollars in thousands)           (Dollars in thousands)
 
$ 15.00       34       3.8     $ 500       34       3.8     $ 500  
  20.10       8       3.8       71       8       3.8       71  
  25.74       22       4.8       84       22       4.8       84  
  26.84       570       5.2       1,562                    
  28.19       30       6.8       42                    
  29.21       7       6.7       3                    
  29.95       592       6.7                          
  34.13       232       5.3             232       5.3        
  37.90       15       2.8             15       2.8        
  38.50       22       5.8                          
  38.85       8       3.2             8       3.2        
  42.08       350       3.3             174       3.3        
  45.78       423       4.3             106       4.3        
  52.98       22       3.8             22       3.8        
                                                     
          2,335       5.1     $ 2,262       621       4.3     $ 655  
                                                     


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following table summarizes information about stock-based awards outstanding at December 31, 2009 (shares in thousands):
 
                                                     
    Options Outstanding   Options 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)   Exerciseble   Years   Intrinsic Value
            (Dollars in thousands)           (Dollars 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  
                                                     
 
The aggregate intrinsic value in the above tables represents the total pretax intrinsic value, based on the Company’s stock price of $29.58 and $37.84 as of December 31, 2010 and 2009, 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, 2010 and 2009 was 64,301 and 183,396, respectively.
 
The total pretax intrinsic value of stock-based award exercised during the years ended December 31, 2009 and 2008 was $1,835,000 and $597,000, respectively, based on the Company’s average stock price of $35.98 and $42.01 during the years ended December 31, 2009 and 2008, respectively. No options were exercised during the year ended December 31, 2010.
 
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, 2010 and 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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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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  
          Weighted
          Weighted
 
          Average
          Average
 
          Exercise
          Exercise
 
    Shares     Price     Shares     Price  
 
Outstanding at beginning of year
    284     $ 3.78       403     $ 3.68  
Exercised
    (284 )     3.78       (97 )     3.78  
Expired
                (1 )     1.75  
Forfeited
                (21 )     1.97  
                                 
Outstanding at end of year
                284       3.78  
                                 
Options exercisable at end of year
                284     $ 3.78  
                                 
 
The total pretax intrinsic value of options exercised during the years ended December 31, 2009 and 2008 was $1,163,000 and $1,130,985 based on the Parent’s average stock price of $7.88 and $13.19 during the year ended December 31, 2009 and 2008, respectively. No options were exercised during the year ended December 31, 2010.
 
NOTE 16 — POWER PURCHASE AGREEMENTS
 
Substantially all of the Company’s electricity revenues are recognized pursuant to PPAs in the U.S. and in various foreign countries, including Kenya, Nicaragua, and Guatemala. These PPAs generally provide for the payment of energy payments or both energy and capacity payments through their respective terms which expire in varying periods from 2014 to 2034. Generally, capacity payments are calculated based on the amount of time that the power plants are available to generate electricity. The energy payments are calculated based on the amount of electrical energy delivered at a designated delivery point. The price terms are customary in the industry and include, among others, a fixed price, short-run avoided cost (“SRAC”) (the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others), and a fixed price with an escalation clause that includes the value for environmental attributes, known as renewable energy credits. Certain of the PPAs provide for bonus payments in the event that the Company is able to exceed certain target levels and potential payments by the Company if it fails to meet minimum target levels. One PPA gives the power purchaser or its designee the right of first refusal to acquire the geothermal power plants at fair market value. Upon satisfaction of certain conditions specified in this PPA and subject to receipt of requisite approvals and negotiations between the parties, the Company has the right to demand that the power purchaser acquire the power plant at fair market value. The Company’s subsidiaries in Nicaragua and Guatemala sell power at an agreed upon price subject to terms of a “take or pay” PPA.
 
Pursuant to the terms of certain of the PPAs, the Company may be required to make payments to the relevant power purchaser under certain conditions, such as shortfall on delivery of renewable energy and energy credits, and not meeting certain performance threshold requirements, as defined. 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


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
lease accounting. Future minimum lease revenues under PPAs which contain a lease element as of December 31, 2010 were as follows:
 
         
    (Dollars in thousands)  
 
Year ending December 31:
       
2011
  $ 200,187  
2012
    199,033  
2013
    201,607  
2014
    203,672  
2015
    206,828  
Thereafter
    2,012,122  
         
Total
  $ 3,023,449  
         
 
NOTE 17 — DISCONTINUED OPERATIONS
 
In January 2010, a former shareholder of Geothermal Development Limited (“GDL”) who is the owner of an 8 MW power plant in New Zealand exercised a call option to purchase from the Company its shares in GDL for approximately $2.8 million. In addition, the Company received $17.7 million to repay the loan a subsidiary of the Company provided to GDL to build the plant. The Company did not exercise its right of first refusal and, therefore, the Company transferred its shares in GDL to the former shareholder after the former shareholder paid all of GDL’s obligations to the Company. As a result, the Company recorded a pre-tax gain of approximately $6.3 million in the year ended December 31, 2010 ($4.3 million after-tax).
 
The net assets of GDL on January 1, 2010 were as follows:
 
         
    (Dollars in thousands)  
 
Cash and cash equivalents
  $ 871  
Accounts receivables
    434  
Prepaid expenses and other
    184  
Property, plant and equipment
    16,293  
Accounts payables and accrued liabilities
    (164 )
Other comprehensive income — translation adjustments
    (156 )
         
Net assets
  $ 17,462  
         
 
The operations and gain on sale of GDL have been included in discontinued operations in the consolidated statements of operations and comprehensive income for all periods prior to the sale of GDL in January 2010. Electricity revenues related to GDL were $3.2 million and $0.9 million in the years ended December 31, 2009 and 2008, respectively none in the year ended December 31, 2010). Basic and diluted earnings per share related to the $4.3 million after-tax gain on sale of GDL was $0.10 in the year ended December 31, 2010. Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations was $0.08 and $(0.05) in the years ended December 31, 2009 and 2008, respectively (none in the year ended December 31, 2010).


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 18 — INTEREST EXPENSE, NET
 
The components of interest expense are as follows:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Dollars in thousands)  
 
Parent
  $ 310     $ 1,121     $ 3,598  
Interest related to sale of tax benefits
    5,429       7,568       7,268  
Other
    44,227       34,947       25,391  
Less — amount capitalized
    (9,493 )     (27,395 )     (21,312 )
                         
    $ 40,473     $ 16,241     $ 14,945  
                         
 
NOTE 19 — INCOME TAXES
 
Income before provision for income taxes and equity in income of investees consisted of:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Dollars in thousands)  
 
U.S. 
  $ (3,715 )   $ 38,371     $ 35,822  
Non-U.S. (foreign)
    34,497       39,989       13,276  
                         
    $ 30,782     $ 78,360     $ 49,098  
                         
 
The components of income tax expense (income) are as follows:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Dollars in thousands)  
 
Current:
                       
State
  $ 115     $ 885     $ (662 )
Foreign
    10,926       12,082       1,779  
                         
    $ 11,041     $ 12,967     $ 1,117  
                         
Deferred:
                       
Federal
    (15,863 )     2,114       3,063  
State
    1,062       1,359       1,295  
Foreign
    2,662       (1,010 )     (165 )
                         
      (12,139 )     2,463       4,193  
                         
    $ (1,098 )   $ 15,430     $ 5,310  
                         


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The significant components of the deferred income tax expense (benefit) are as follows:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Dollars in thousands)  
 
Deferred tax expense (exclusive of the effect of other components listed below)
  $ 16,480     $ (6,082 )   $ 6,014  
Benefit of operating loss carryforwards — U.S. 
    (45,540 )     (23,036 )     4,278  
Change in foreign income tax
    9,008       9,134       402  
Change in lease transaction
    769       3,919       (943 )
Change in tax monetization transaction
    8,690       7,858       4,947  
Change in intangible drilling costs
    12,497       21,659        
Benefit of production tax credits
    (14,043 )     (10,989 )     (10,505 )
                         
    $ (12,139 )   $ 2,463     $ 4,193  
                         
 
The difference between the U.S. federal statutory tax rate and the Company’s effective tax rate are as follows:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
 
U.S. federal statutory tax rate
    35.0 %     35.0 %     35.0 %
State income tax, net of federal benefit
    3.2       2.6       1.4  
Effect of foreign income tax, net
    4.5       (3.8 )     (6.3 )
Production tax credits
    (45.7 )     (13.2 )     (22.9 )
Other, net
    (0.7 )     (0.3 )     2.3  
                         
Effective tax rate
    (3.7 )%     20.3 %     9.5 %
                         
 
The net deferred tax assets and liabilities consist of the following:
 
                 
    December 31,  
    2010     2009  
    (Dollars in thousands)  
 
Deferred tax assets (liabilities):
               
Net foreign deferred taxes, primarily depreciation
  $ (30,233 )   $ (21,225 )
Depreciation
    (80,318 )     (74,961 )
Intangible drilling costs
    (34,156 )     (21,659 )
Net capital loss carryforward — U.S. 
    95,536       49,996  
Tax monetization transaction
    (26,092 )     (17,402 )
Lease transaction
    5,609       6,378  
Investment tax credits
    1,971       1,971  
Production tax credits
    48,255       34,212  
Stock options amortization
    2,276       1,375  
Unconsolidated investment
          (5,949 )
Accrued liabilities and other
    5,468       (2,841 )
                 
      (11,684 )     (50,105 )
Less valuation allowance
    (433 )      
                 
Total
  $ (12,117 )   $ (50,105 )
                 


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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, 2010, net of an immaterial valuation allowance related to state income taxes of $0.4 million, will be realized.
 
At December 31, 2010, the Company had U.S. federal NOL carryforwards of approximately $255.8 million and state NOL carryforwards of approximately $105.5 million, net of valuation allowance of $0.6 million, available to reduce future taxable income, which expire between 2021 and 2031 for federal NOLs and between 2015 and 2031 for state NOLs. The investment tax credits in the amount of $2.0 million at December 31, 2010 are available for a 20-year period and expire in 2022 and 2024. The production tax credits in the amount of $48.3 million at December 31, 2010 are available for a 20-year period and expire between 2026 and 2031.
 
The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $196.5 million at December 31, 2010. 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 liability for unrecognized tax benefits of $5.4 million and $4.9 million at December 31, 2010 and 2009, 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,  
    2010     2009     2008  
    (Dollars in thousands)  
 
Balance at beginning of year
  $ 4,931     $ 3,425     $ 5,330  
Additions based on tax positions taken in prior years
    823       964       929  
Additions based on tax positions taken in the current year
    260       1,282       814  
Reduction based on tax positions taken in prior years
    (583 )            
Decrease for settlements with taxing authorities
          (740 )     (3,648 )
                         
Balance at end of year
  $ 5,431     $ 4,931     $ 3,425  
                         
 
The Company and its U.S. subsidiaries file consolidated income tax returns for federal and state purposes. As of December 31, 2010, 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 2000-2010 and by local state jurisdictions for the years 2002-2010.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 — 2010
Nicaragua
  2006 — 2010
Kenya
  2006 — 2010
Guatemala
  2005 — 2010
Philippines
  2006 — 2010
New Zealand
  2005 — 2010
 
Management believes that the liability for unrecognized tax benefits is adequate for all open tax years based on its assessment of many factors, including among others, past experience and interpretations of local income tax regulations. This assessment relies on estimates and assumptions and may involve a series of complex judgments about future events. As a result, it is possible that federal, state and foreign tax examinations will result in assessments in future periods. To the extent any such assessments occur, the Company will adjust its liability for unrecognized tax benefits.
 
Tax benefits in the U.S.
 
The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies under the recently enacted the ARRA. 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 2010 was 2.2 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 place qualifying renewable energy facilities in service, during 2009, 2010 or 2011, or that begin construction of qualifying renewable energy facilities during 2009, 2010 or 2011 and place them in service by December 31, 2013, may choose to apply for a cash grant from the U.S. Treasury in an amount equal to the investment tax credit. Under the ARRA, the U.S. Treasury is instructed to pay the cash grant within 60 days of the application or the date on which the qualifying facility is placed in service.
 
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 13).
 
Income taxes related to foreign operations
 
Guatemala — The enacted tax rate is 31%. Orzunil, a wholly owned subsidiary, was granted a benefit under a law which promotes development of renewable power sources. The law allows Orzunil to reduce the investment made in its geothermal power plant from income tax payable, which reduces the effective tax rate to zero. Ortitlan, another wholly owned subsidiary, was granted a tax exemption for a period of ten years ending August 2017. The effect of the tax exemption in the years ended December 31, 2010, 2009, and 2008 is $3.2 million, $3.8 million, and $3.9 million, respectively ($0.07, $0.08, and $0.09 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 27% in 2008, 26% in 2009, 25% in 2010, 24% in


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 arm’s length, and that the management and control of Ormat Systems will be from Israel during the whole period of the tax benefits. A change in control should be reported to the Israel Tax Authority in order to maintain the tax benefits. In January 2011, new legislation amending the Investment Law was enacted. Under the new legislation, a uniform rate of corporate tax would apply to all qualified income of certain industrial companies, as opposed to the current law’s incentives that are limited to income from a “Benefited Enterprise” during their benefits period. According to the amendment, the uniform tax rate applicable to the zone where the production facilities of Ormat Systems are located would be 15% in 2011 and 2012, 12.5% in 2013 and 2014, and 12% in 2015 and thereafter. Under the transitory provisions of the new legislation, Ormat Systems may opt whether to irrevocably implement the new law while waiving benefits provided under the current law or keep implementing the current law during the next years. Changing from the current law to the new law is permissible at any stage.
 
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 20 — 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.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Summarized financial information concerning the Company’s reportable segments is shown in the following tables:
 
                         
    Electricity   Product   Consolidated
    (Dollars in thousands)
 
Year Ended December 31, 2010
                       
Net revenues from external customers
  $ 291,820     $ 81,410     $ 373,230  
Intersegment revenues
          70,275       70,275  
Depreciation and amortization expense
    84,276       2,485       86,761  
Operating income
    12,782       10,786       23,568  
Segment assets at year end*
    1,954,778       88,550       2,043,328  
Expenditures for long-lived assets
    280,090       3,223       283,313  
                         
* Including unconsolidated investments
    2,244       2,000       4,244  
                         
Year Ended December 31, 2009
                       
Net revenues from external customers
  $ 252,621     $ 159,389     $ 412,010  
Intersegment revenues
          33,751       33,751  
Depreciation and amortization expense
    62,283       2,093       64,376  
Operating income
    45,335       21,259       66,594  
Segment assets at year end*
    1,766,519       97,674       1,864,193  
Expenditures for long-lived assets
    265,252       5,371       270,623  
                         
* Including unconsolidated investments
    35,188             35,188  
                         
Year Ended December 31, 2008
                       
Net revenues from external customers
  $ 251,373     $ 92,577     $ 343,950  
Intersegment revenues
          81,557       81,557  
Depreciation and amortization expense
    58,560       1,568       60,128  
Operating income
    44,979       5,673       50,652  
Segment assets at year end*
    1,555,315       75,661       1,630,976  
Expenditures for long-lived assets
    412,734       3,872       416,606  
                         
* Including unconsolidated investments
    30,131             30,131  


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Reconciling information between reportable segments and the Company’s consolidated totals is shown in the following table:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Dollars in thousands)  
 
Revenues:
                       
Total segment revenues
  $ 373,230     $ 412,010     $ 343,950  
Intersegment revenues
    70,275       33,751       81,557  
Elimination of intersegment revenues
    (70,275 )     (33,751 )     (81,557 )
                         
Total consolidated revenues
  $ 373,230     $ 412,010     $ 343,950  
                         
Operating income:
                       
Operating income
  $ 23,568     $ 66,594     $ 50,652  
Interest income
    343       639       3,118  
Interest expense, net
    (40,473 )     (16,241 )     (14,945 )
Foreign currency translation and transaction gains (losses)
    1,557       (1,695 )     (8,616 )
Income attributable to sale of equity interest
    8,729       15,515       18,118  
Gain from extinguishment of liability
          13,348        
Gain on acquisition of controlling interest
    36,928              
Other non-operating income, net
    130       200       771  
                         
Total consolidated income before income taxes and equity in income of investees
  $ 30,782     $ 78,360     $ 49,098  
                         
 
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,  
    2010     2009     2008  
    (Dollars in thousands)  
 
Revenues from external customers attributable to:(1)
                       
North America
  $ 241,732     $ 248,357     $ 252,557  
Pacific Rim
    6,878       28,924       20,375  
Latin America
    57,853       79,683       33,874  
Africa
    35,225       34,857       10,704  
Far East
    1,964       3,850       6,030  
Europe
    29,578       16,339       20,410  
                         
Consolidated total
  $ 373,230     $ 412,010     $ 343,950  
                         
 
 
(1) Revenues as reported in the geographic area in which they originate.
 


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                         
    December 31,  
    2010     2009     2008  
    (Dollars in thousands)  
 
Long-lived assets (primarily power plants and related assets) located in:
                       
North America
  $ 1,536,583     $ 1,341,863     $ 1,181,714  
Latin America
    89,980       80,687       94,464  
Africa
    115,245       131,997       113,157  
Europe
    13,584       12,846       9,572  
Pacific Rim and Far East
          12,816       9,873  
                         
Consolidated total
  $ 1,755,392     $ 1,580,209     $ 1,408,780  
                         
 
The following table presents revenues from major customers:
 
                                                 
    Year Ended December 31,  
    2010     2009     2008  
    Revenues     %     Revenues     %     Revenues     %  
    (Dollars in
          (Dollars in
          (Dollars in
       
    thousands)           thousands)           thousands)        
 
SCE(1)
  $ 108,481       29.1     $ 87,017       21.1     $ 95,254       27.7  
Hawaii Electric Light Company(1)
    32,194       8.6       25,979       6.3       57,679       16.8  
Sierra Pacific Power Company and Nevada Power Company(1)(2)
    55,877       15.0       53,658       13.0       43,406       12.6  
NGP Blue Mountain I LLC(3)
                46,893       11.4       32,646       9.5  
Central American Bank for Economic
                                               
Integration (Las Pailas Project)(3)
    21,365       5.7       44,073       10.7              
 
 
(1) Revenues reported in Electricity Segment.
 
(2) Subsidiaries of NV Energy, Inc.
 
(3) Revenues reported in Products Segment.
 
NOTE 21 — TRANSACTIONS WITH RELATED ENTITIES
 
Transactions between the Company and related entities, other than those disclosed elsewhere in these financial statements, are summarized below:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Dollars in thousands)  
 
Property rental fee expense paid to the Parent
  $ 1,680     $ 1,380     $ 656  
                         
Interest expense on note payable to Parent
  $ 310     $ 1,125     $ 3,597  
                         
Corporate financial, administrative, executive services, and research and development services provided to the Parent
  $ 139     $ 170     $ 152  
                         
Services rendered by an indirect shareholder of the Parent
  $ 116     $ 91     $ 110  
                         
 
The current liability due from Parent at December 31, 2010 and 2009 of $272,000 and $422,000, respectively, represents the net obligation resulting from ongoing operations and transactions with the Parent and is payable from available cash flow. Interest is computed on balances greater than 60 days at LIBOR plus 1% (but not less than the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 was payable in varying amounts through the loan due date of June 2010. The outstanding balance of such loan at December 31, 2009 was $9,600,000 (which represented the then-current portion). The loan was fully repaid in the year ended 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 entered into in July 2004 for the sublease of office and manufacturing facilities in Yavne, Israel, for a monthly rent of $52,000, adjusted annually for changes in the Israeli Consumer Price Index, plus taxes and other costs to maintain the properties. The term of the rental agreement is for a period ending the earlier of: (i) 25 years from July 1, 2004; or (ii) the remaining periods of the underlying lease agreements between the Parent and the Israel Land Administration (which terminate between 2018 and 2047).
 
Effective April 1, 2009, Ormat Systems entered into an additional rental agreement with the Parent for the sublease of additional manufacturing facilities adjacent to the current manufacturing facilities in Yavne, Israel. The term of the additional rent agreement will expire on the same day as the abovementioned lease agreement entered into in July 2004. Pursuant to the additional lease agreement, Ormat Systems pays a monthly rent of $77,000, adjusted annually for changes in the Israeli Consumer Price Index, plus tax and other costs to maintain the properties.
 
Registration rights agreement
 
Prior to the closing of the Company’s initial public offering in November 2004, the Company and the Parent entered into a registration rights agreement pursuant to which the Parent may require the Company to register its 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 22 — EMPLOYEE BENEFIT PLAN
 
401(k) Plan
 
The Company has a 401(k) Plan (the “Plan”) for the benefit of its U.S. employees. Employees of the Company and its U.S. subsidiaries who have completed one year of service or who had one year of service upon establishment of the Plan are eligible to participate in the Plan. Contributions are made by employees through pretax deductions up to 60% of their annual salary. Contributions made by the Company are matched up to a maximum of 2% of the


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
employee’s annual salary. The Company’s contributions to the Plan were $451,000, $364,000, and $301,000 for the years ended December 31, 2010, 2009, and 2008, 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 in the consolidated balance sheets as “liabilities for severance pay”. The Company has an obligation to partially fund the liabilities through regular deposits in pension funds and severance pay funds. The amounts funded amounted to $18,562,000 and $16,274,000 at December 31, 2010 and 2009, respectively, and have been presented in the consolidated balance sheets as part of “deposits and other”. The severance pay liability covered by the pension funds is not reflected in the financial statements as the severance pay risks have been irrevocably transferred to the pension funds. Under the Israeli severance pay law, restricted funds may not be withdrawn or pledged until the respective severance pay obligations have been met. As allowed under the program, earnings from the investment are used to offset severance pay costs. Severance pay expenses for the years ended December 31, 2010, 2009, and 2008 were $1,676,000, $1,148,000, and $2,843,000, respectively, which are net of income amounting to $1,889,000, $1,613,000, and $324,000, respectively, generated from the regular deposits and amounts accrued in severance funds
 
The Company expects the severance pay contributions in 2011 to be approximately $1.8 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:
       
2011
  $ 3,792  
2012
    1,197  
2013
    889  
2014
    600  
2015
    795  
2016-2020
    8,640  
         
    $ 15,913  
         
 
The above amounts were determined based on the employees’ current salary rates and the number of years’ service that will have been accumulated at their retirement date. These amounts do not include amounts that might be paid to employees that will cease working with the Company before reaching their normal retirement age.
 
NOTE 23 — COMMITMENTS AND CONTINGENCIES
 
Geothermal resources
 
The Company, through its project subsidiaries in the United States, controls certain rights to geothermal fluids through certain leases with the Bureau of Land Management (“BLM”) or through private leases. Royalties on the utilization of the geothermal resources are computed and paid to the lessors as defined in the respective agreements. Royalty expense under the geothermal resource agreements were $8,690,000, $6,611,000, and $10,737,000 for the years ended December 31, 2010, 2009, and 2008, respectively.


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 $67.0 million and $53.4 million at December 31, 2010 and 2009, 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, 2010, total obligations related to such supplier agreements were approximately $56.6 million (out of which approximately $36.8 million relate to construction-in-process). All such obligations are payable in 2011.
 
Grants and royalties
 
The Company, through Ormat Systems, had historically, through December 31, 2003, requested and received grants for research and development from the Office of the Chief Scientist of the Israeli Government. Ormat Systems is required to pay royalties to the Israeli Government at a rate of 3.5% to 5.0% of the revenues derived from products and services developed using these grants. No royalties were paid for the years ended December 31, 2010, 2009, and 2008. The Company is not liable for royalties if the Company does not sell such products and services. Such royalties are capped at the amount of the grants received plus interest at LIBOR. The cap at December 31, 2010 and 2009, amounted to $1,343,000 and $1,284,000, respectively, of which approximately $402,000 and $343,000 of the cap, respectively, increases based on the LIBOR rate, as defined above.
 
Contingencies
 
Securities Class Actions
 
Following the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs, three securities class action lawsuits were filed in the United States District Court for the District of Nevada on March 9, 2010, March 18, 2010 and April 7, 2010. These complaints assert claims against the Company and certain officers and directors for alleged violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (the “Exchange Act”). One complaint also asserts claims for alleged violations of Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 (the “Securities Act”). All three complaints allege claims on behalf of a putative class of purchasers of Company stock between May 6, 2008 or May 7, 2008 and February 23, 2010 or February 24, 2010.
 
These three lawsuits were consolidated by the Court in an order issued on June 3, 2010 and the Court appointed three of the Company’s stockholders to serve as lead plaintiffs. Lead plaintiffs filed a consolidated amended class action complaint (“CAC”) on July 9, 2010 that asserts claims under Sections 10(b) and 20(a) of the Exchange Act on behalf of a putative class of purchasers of Company stock between May 7, 2008 and February 24, 2010. The CAC alleges that certain of the Company’s public statements were false and misleading for failing to account properly for the Company’s exploration and development costs based on the Company’s announcement on February 24, 2010 that it was going to restate its financial results to change its method of accounting for exploration and development costs in certain respects. The CAC also alleges that certain of the Company’s statements concerning the North


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Brawley project were false and misleading. The CAC seeks compensatory damages, expenses, and such further relief as the Court may deem proper. The Company cannot make an estimate of the possible loss or range of loss.
 
Defendants filed a motion to dismiss the CAC on August 13, 2010 which remains pending.
 
The Company does not believe that these lawsuits have merit and is defending the actions vigorously.
 
Stockholder Derivative Cases
 
Four stockholder derivative lawsuits have also been filed in connection with the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs. Two cases were filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe on March 16, 2010 and April 21, 2010 and two in the United States District Court for the District of Nevada on March 29, 2010 and June 7, 2010. All four lawsuits assert claims brought derivatively on behalf of the Company against certain of its officers and directors for alleged breach of fiduciary duty and other claims, including waste of corporate assets and unjust enrichment.
 
The two stockholder derivative cases filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe were consolidated by the Court in an order dated May 27, 2010 and the plaintiffs filed a consolidated derivative complaint on September 7, 2010. In accordance with a stipulation between the parties, defendants filed a motion to dismiss on November 16, 2010 which remains pending. The Company cannot make an estimate of the possible loss or range of loss on the state derivative cases.
 
The two federal derivative cases filed in the United States District Court for the District of Nevada were consolidated by the Court in an order dated August 31, 2010. Plaintiffs filed a consolidated derivative complaint on October 28, 2010 and in accordance with a stipulation by the parties, defendants filed a motion to dismiss on December 13, 2010 which remains pending. The Company cannot make an estimate of the possible loss or range of loss on the federal derivative cases.
 
The Company believes the allegations in these purported derivative actions are also without merit and is defending the actions vigorously.
 
Other
 
From time to time, the Company is named as a party in various lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of its business. These actions typically seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to such lawsuits, claims and proceedings, the Company accrues reserves in accordance with accounting principles generally accepted in the U.S. It is the opinion of the Company’s management that the outcome of these proceedings, individually and collectively, will not materially affect its business, financial condition, financial results or cash flow.


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 24 — QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
 
                                                                 
    Three Months Ended  
    March 31,
    June 30,
    Sept. 30,
    Dec. 31,
    March 31,
    June 30,
    Sept. 30,
    Dec. 31,
 
    2009     2009     2009     2009(1)     2010     2010(2)     2010     2010  
    (Dollars in thousands, except per share amounts)  
 
Revenues:
                                                               
Electricity
  $ 62,060     $ 59,826     $ 67,913       62,822     $ 66,105     $ 68,807     $ 83,357     $ 73,551  
Product
    37,251       39,673       51,113       31,352       16,549       27,459       18,120       19,282  
                                                                 
Total revenues
    99,311       99,499       119,026       94,174       82,654       96,266       101,477       92,833  
                                                                 
Cost of revenues:
                                                               
Electricity
    43,686       44,718       44,085       46,612       54,523       63,498       61,530       62,775  
Product
    24,243       27,242       35,780       25,185       12,437       14,115       14,764       11,961  
                                                                 
Total cost of revenues
    67,929       71,960       79,865       71,797       66,960       77,613       76,294       74,736  
                                                                 
Gross margin
    31,382       27,539       39,161       22,377       15,694       18,653       25,183       18,097  
Operating expenses:
                                                               
Research and development expenses
    801       2,487       3,863       3,351       3,267       3,614       1,252       1,987  
Selling and marketing expenses
    4,301       3,215       3,393       3,675       3,202       2,686       3,333       4,226  
General and administrative expenses
    7,535       5,582       6,437       6,858       7,020       6,996       5,780       7,646  
Write-off of unsuccessful exploration activities
                2,367                   3,050              
                                                                 
Operating income
    18,745       16,255       23,101       8,493       2,205       2,307       14,818       4,238  
Other income (expense):
                                                               
Interest income
    152       276       157       54       197       95       140       (89 )
Interest expense, net
    (3,290 )     (4,415 )     (4,358 )     (4,178 )     (9,714 )     (9,426 )     (10,961 )     (10,372 )
Foreign currency translation and transaction gains (losses)
    (2,393 )     1,044       25       (371 )     434       (1,033 )     1,074       1,082  
Impairment of auction rate securities
    (279 )                                         (137 )
Income attributable to sale of tax benefits
    4,168       4,366       3,869       3,112       2,139       2,070       2,183       2,337  
Gain on acquisition of controlling interest
                                        36,928        
Gain from extinguishment of liability
                      13,348                          
Other non-operating income (expense), net
    129       550       246       (446 )     (359 )     79       233       314  
                                                                 
Income (loss) from continuing operations, before income taxes and equity in income of investees
    17,232       18,076       23,040       20,012       (5,098 )     (5,908 )     44,415       (2,627 )
Income tax benefit (provision)
    (3,429 )     (3,868 )     (2,935 )     (5,198 )     2,557       3,365       (11,931 )     7,107  
Equity in income (losses) of investees
    550       355       591       640       546       479       (83 )     56  
                                                                 
Income (loss) from continuing operations
    14,353       14,563       20,696       15,454       (1,995 )     (2,064 )     32,401       4,536  
Discontinued operations:
                                                               
Income from discontinued operations, net of related tax
    153       1,411       1,251       672       14                    
Gain on sale of a subsidiary in New Zealand, net of tax
                            3,766       570              
                                                                 
Net Income (loss)
    14,506       15,974       21,947       16,126       1,785       (1,494 )     32,401       4,536  
Net loss (income) attributable to noncontrolling interest
    79       77       80       62       53       57       58       (78 )
                                                                 
Net income (loss) attributable to the Company’s stockholders
  $ 14,585     $ 16,051     $ 22,027     $ 16,188     $ 1,838     $ (1,437 )   $ 32,459     $ 4,458  
                                                                 
Earnings (loss) per share attributable to the Company’s stockholders:
                                                               
Basic:
                                                               
Income (loss) from continuing operations
  $ 0.32     $ 0.32     $ 0.45     $ 0.35     $ (0.04 )   $ (0.05 )   $ 0.71     $ 0.10  
Discontinued operations
          0.03       0.03       0.01       0.08       0.02              
                                                                 
Net income (loss)
  $ 0.32     $ 0.35     $ 0.48     $ 0.36     $ 0.04     $ (0.03 )   $ 0.71     $ 0.10  
                                                                 
Diluted:
                                                               
Income (loss) from continuing operations
  $ 0.32     $ 0.32     $ 0.45     $ 0.34     $ (0.04 )   $ (0.05 )   $ 0.71     $ 0.10  
Discontinued operations
          0.03       0.03       0.01       0.08       0.02              
                                                                 
Net income (loss)
  $ 0.32     $ 0.35     $ 0.48     $ 0.35     $ 0.04     $ (0.03 )   $ 0.71     $ 0.10  
                                                                 
Weighted average number of shares used in computation of earnings (loss) per share attributable to the Company’s stockholders:
                                                               
Basic
    45,353       45,369       45,413       45,426       45,431       45,431       45,431       45,431  
                                                                 
Diluted
    45,405       45,451       45,564       45,623       45,457       45,431       45,450       45,450  
                                                                 


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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
(1) 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.
 
(2) Included in income from discontinued operations for the three months ended December June 30, 2010 is an out-of-period adjustment of $570,000 that increased the after-tax gain on the sale of GDL. Such adjustment relates to an error in income taxes associated with the gain on sale of GDL in the three months ended March 31, 2010 (see Note 6)
 
NOTE 25 — SUBSEQUENT EVENTS
 
Senior Unsecured Bonds
 
In February 2011, the Company accepted subscriptions for an aggregate principal amount of $107.5 million of additional senior unsecured bonds (see Note 11).
 
OPC Transaction
 
On February 3, 2011, Ormat Nevada sold to JPM all of the Class B membership units of OPC that it had acquired on October 30, 2010 for $24.9 million in cash (see Note 13).
 
Cash dividend
 
On February 22, 2011, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $2.3 million ($0.05 per share) to all holders of the Company’s issued and outstanding shares of common stock on March 15, 2011, payable on March 24, 2011.


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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, 2010, 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.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.
 
Management, under the supervision and participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010 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, 2010.
 
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2010 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
 
Changes in Internal Control over Financial Reporting
 
No changes in the Company’s internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act, have been identified during the Company’s fourth fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
 
ITEM 9B.   OTHER INFORMATION
 
None.


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PART III
 
ITEM 10.   DIRECTORS 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 Y. Bronicki
    77     Chairman of the Board of Directors; Chief Technology Officer(3)
Yehudit “Dita” Bronicki
    69     Chief Executive Officer; Director(2)
Yoram Bronicki
    44     President; Chief Operating Officer; Director(1)
Joseph Tenne
    55     Chief Financial Officer*
Nadav Amir
    60     Executive Vice President — Operations*
Zvi Reiss
    60     Executive Vice President — Project Management*
Joseph Shiloah
    65     Executive Vice President — Business Development, Rest of the World*
Zvi Krieger
    55     Executive Vice President — Geothermal Resource*
Shimon Hatzir
    49     Senior Vice President — Engineering*
Etty Rosner
    55     Senior Vice President — Contract Management; Corporate Secretary*
Nir Wolf
    45     Vice President — Marketing and Sales, Rest of the World*
Independent Directors:
           
Dan Falk
    66     Independent Director(3)
Roger W. Gale
    64     Independent Director(1)
Robert F. Clarke
    68     Independent Director(2)
David Wagener
    56     Independent Director(2)
 
 
* Performs the functions described in the table, but is employed by Ormat Systems.
 
(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 2013 Annual Shareholders Meeting.
 
Lucien Y. Bronicki.  Lucien Y. 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 various 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 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


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married and are the parents of Yoram Bronicki. Mr. Bronicki obtained a postgraduate degree in Nuclear Engineering from Conservatoire National des Arts et Métiers, a Master of Science in Physics from Universite de Paris and a Master of Science in Mechanical Engineering from École Nationale Supérieure d’Ingenieurs Arts et Métiers. He received a Ph.D. Honoris Causa in 2005 from the Ben-Gurion University, in 2006 from the Weizmann Institute of Science, and in 2007 from the Technion — Israel Institute of Technology.
 
Yehudit “Dita” Bronicki.  Yehudit Bronicki has been our Chief Executive Officer since July 1, 2004, and is also a member of our Board of Directors. From July 1, 2004 to September 20, 2007, Mrs. Bronicki also served as our President. Mrs. Bronicki was a co-founder of Ormat Turbines Ltd. and is a member of the Board of Directors and the General Manager (a CEO-equivalent position) of Ormat Industries Ltd., the publicly traded successor to Ormat Turbines Ltd., and several of its subsidiaries. From 1992 to June 2005, Mrs. Bronicki was a director of Bet Shemesh Engines, a manufacturer of jet engines. In addition, until May 2005, Mrs. Bronicki was a member of the Board of Directors of OPTI Canada Inc., a company engaged in the oil sands industry in Canada and in which our parent owns an approximately 5% interest, 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. In 2007, she received a PhD. Honoris Causa from the Technion — Israel Institute of Technology.
 
Yoram Bronicki.  Yoram Bronicki has been a member of our Board of Directors since November 12, 2004, and has been our President and Chief Operating Officer since September 20, 2007. From July 1, 2004 to September 20, 2007, Mr. Bronicki was our Chief Operating Officer, North America. Mr. Bronicki is also a member of the Board of Directors of Ormat Industries Ltd., a position he has held since 2001. 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 and a Certificate and a Certificate from the Technion Institute of Management Senior Executives Program.
 
Joseph Tenne.  Joseph Tenne has served as our Chief Financial Officer since March 9, 2005. From 2003 to 2004, Mr. Tenne was the Chief Financial Officer of Treofan Germany GmbH & Co. KG, a German company. From 1997 until 2003, Mr. Tenne was a partner in Kesselman & Kesselman, Certified Public Accountants in Israel (a member firm of PricewaterhouseCoopers International Limited). Since January 8, 2006, Mr. Tenne has also been the Chief Financial Officer of Ormat Industries Ltd. Mr. Tenne is a member of the board of directors of 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 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 Business Development, Rest of the World since January 1, 2010.  From July 1, 2004 to December 31, 2009, Mr. Shiloah served as our Executive


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Vice President of Marketing and Sales, Rest of the World; from 2001 to June 30, 2004, he was the Executive Vice President of Marketing and Sales of 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.
 
Nir Wolf.  Nir Wolf has served as our Vice President for Marketing and Sales, Rest of the World since January 1, 2010. From December 2005 to December 31, 2009, Mr. Wolf served as our Vice President Distributed Power responsible for the marketing, sales, engineering and after sales activities of the remote power units. From December 1999 to December 2005, Mr. Wolf had a leading position as Business Development Manager in the Marketing and Sales Department. Starting January 14, 1994, when Mr. Wolf joined us, he was positioned in the Project Management Department as a Budget and Schedule Controller and later on as a Project Manager. Mr. Wolf obtained a Bachelor of Science in Industrial Engineering, cum laude from the Technion — Israel Institute of Technology in 1991. In 1995, Mr. Wolf obtained a Master of Business Administration from the Bar Ilan University. Mr. Wolf participated in the Technion Institute of Management Senior Executive Program.
 
Dan Falk.  Dan Falk has been a member of our Board of Directors since November 12, 2004. Mr. Falk also serves as the Chairman of the Board of Directors of Orad Hi-Tech Systems Ltd., a public non-U.S. company. He is also a member of the Board of Directors of Orbotech Ltd., Nice Systems Ltd., Attunity Ltd., and Nova Measuring Instruments Ltd., all NASDAQ publicly traded companies. In addition, Mr. Falk serves as a member of the Board of Directors of the following public non-US companies: 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 Directors of the following public companies, for which he no longer serves as a Director: AVT Ltd., Clicksoftware Technologies Ltd., Dmatek Ltd., Jacada Ltd., Poalim Ventures I 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 N.V. From 1995 to 1999, Mr. Falk was an Executive


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Vice President of Orbotech Ltd. From 1985 to 1995, Mr. Falk was Vice President of Finance and Chief Financial Officer of Orbot Systems Ltd. and Orbotech Ltd. Mr. Falk obtained a Masters of Business Administration from Hebrew University in 1972 and a Bachelor of Arts in Economics and Political Science from Hebrew University in 1968. Mr. Falk is the Chair of our Audit Committee. Our Board of Directors has determined that Mr. Falk qualifies as an Audit Committee “financial 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 & Resources Corporation (closed-end investment companies). He served on the Audit Committee of Constellation Holdings and on the Board of Directors 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, and as a member of the advisory boards of the Shidler College of Business at the University of Hawaii, of Sennet Capital, and of Aina Koa Pono, a Hawaii based privately held company exploring renewable energy projects in converting biomass into fuels. Mr. Clarke joined HEI in February 1987 as Vice President of Strategic Planning and was in charge of implementing the Company’s diversification strategy. Mr. Clarke was named HEI Group Vice President — Diversified Companies in May 1988. He was made a director of HEI in 1989. Prior to joining HEI, Mr. Clarke served as Senior Vice President and Chief Financial Officer of Alexander & Baldwin and as Controller of Dillingham Corporation. Prior to that, he worked for the Ford Motor Company and for the Singer Company. He received his Bachelor’s degree in economics in 1965 and his Master’s degree in finance in 1966 from the University of California at Berkeley. Honors include Phi Beta Kappa in 1965.
 
David Wagener.  David Wagener has been a member of our Board of Directors since 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. Wagener serves on the Board of Directors of Suncor Development Company, a subsidiary of Pinnacle West Capital Corporation. 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 2011 Proxy Statement.


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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 2011 Proxy Statement.
 
ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 
The information required under this item is incorporated by reference herein from the Company’s definitive 2011 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 2011 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.


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Exhibit
   
No.   Document
 
  4 .5   Indenture for Subordinated Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.
  4 .6   Deed of Trust, dated as of August 3, 2010, between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 2, 2011.
  4 .7   Addendum, dated as of January 27, 2011, to the Deed of Trust, dated as of August 3, 2010, between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 2, 2011.
  4 .8   Form of Bond issued pursuant to the Deed of Trust, dated as of August 3, 2010 (as amended or supplemented), between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 2, 2011.
  10 .1.1   Indenture, dated February 13, 2004, among Ormat Funding Corp., Brady Power Partners, Steamboat Development Corp., Steamboat Geothermal LLC, OrMammoth Inc., ORNI 1 LLC, ORNI 2 LLC, ORNI 7 LLC, Ormesa LLC and Union Bank of California, incorporated by reference to Exhibit 10.1.7 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .1.2   First Supplemental Indenture, dated May 14, 2004, among Ormat Funding Corp., Brady Power Partners, Steamboat Development Corp., Steamboat Geothermal LLC, OrMammoth Inc., ORNI 1 LLC, ORNI 2 LLC, ORNI 7 LLC, Ormesa LLC and Union Bank of California, incorporated by reference to Exhibit 10.1.8 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .1.3   Fifth Supplemental Indenture, dated April 26, 2006, among Ormat Funding Corp. and Union Bank of California, N.A., incorporated by reference to Exhibit 10.1.6 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q (File No 001-32347) to the Securities and Exchange Commission on August 7, 2006.
  10 .1.4   Loan Agreement, dated October 1, 2003, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.9 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .1.5   Amendment No. 1 to Loan Agreement, dated September 20, 2004, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.10 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .1.6   Guarantee Fee Agreement, dated January 1, 1999, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.13 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .1.7   Reimbursement Agreement, dated July 15, 2004, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.14 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .1.8   Services Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd., incorporated by reference to Exhibit 10.1.15 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.


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Exhibit
   
No.   Document
 
  10 .1.9   Agreement for Purchase of Membership Interests in OPC LLC dated June 7, 2007, by and among Ormat Nevada Inc., Morgan Stanley Geothermal LLC and Lehman-OPC LLC, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on June 13, 2007.
  10 .1.10   First Amendment to Agreement for Purchase of Membership Interests in OPC LLC, dated as of April 17, 2008, by and among Ormat Nevada Inc., Morgan Stanley Geothermal LLC, and Lehman-OPC LLC, incorporated by reference to Exhibit 10.1.18 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on May 7, 2008.
  10 .1.11   Membership Interest Purchase Agreement, dated as of October 30, 2009, by and among Lehman-OPC LLC, Ormat Nevada Inc. and OPC LLC, incorporated by reference to Exhibit 10.1.13 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on November 3, 2009.
  10 .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.


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Exhibit
   
No.   Document
 
  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.
  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.


189


 

         
Exhibit
   
No.   Document
 
  10 .2.24   Plant Connection Agreement for the Second Imperial Geothermal Company Power Plant No. 1, dated, October 27, 1992, by and between Imperial Irrigation District and Second Imperial Geothermal Company incorporated by reference to Exhibit 10.3.24 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.25   IID-SIGC Transmission Service Agreement for Alternative Resources, dated, October 27, 1992, by and between Imperial Irrigation District and Second Imperial Geothermal Company incorporated by reference to Exhibit 10.3.25 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  10 .2.26   Plant Connection Agreement for the Ormesa Geothermal Plant, dated October 1, 1985, by and between Imperial Irrigation District and Ormesa Geothermal incorporated by reference to Exhibit 10.3.26 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.27   Plant Connection Agreement for the Ormesa IE Geothermal Plant, dated, October 21, 1988, by and between Imperial Irrigation District and Ormesa IE incorporated by reference to Exhibit 10.3.27 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.28   Plant Connection Agreement for the Ormesa IH Geothermal Plant, dated, October 3, 1989, by and between Imperial Irrigation District and Ormesa IH incorporated by reference to Exhibit 10.3.28 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.29   Plant Connection Agreement for the Geo East Mesa Limited Partnership Unit No. 2, dated, March 21, 1989, by and between Imperial Irrigation District and Geo East Mesa Limited Partnership incorporated by reference to Exhibit 10.3.29 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.30   Plant Connection Agreement for the Geo East Mesa Limited Partnership Unit No. 3, dated, March 21, 1989, by and between Imperial Irrigation District and Geo East Mesa Limited Partnership incorporated by reference to Exhibit 10.3.30 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.31   Transmission Service Agreement for the Ormesa I, Ormesa IE and Ormesa IH Geothermal Power Plants, dated, October 3, 1989, between Imperial Irrigation District and Ormesa Geothermal incorporated by reference to Exhibit 10.3.31 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.32   Transmission Service Agreement for the Geo East Mesa Limited Partnership Unit No. 2, dated, March 21, 1989, by and between Imperial Irrigation District and Geo East Mesa Limited Partnership incorporated by reference to Exhibit 10.3.32 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  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.


190


 

         
Exhibit
   
No.   Document
 
  10 .2.36   Agreement Addressing Renewable Energy Pricing and Payment Issues, dated June 15, 2001, by and between Second Imperial Geothermal Company QFID No. 3021 and Southern California Edison Company incorporated by reference to Exhibit 10.3.39 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.37   Amendment No. 1 to Agreement Addressing Renewable Energy Pricing and Payment Issues, dated November 30, 2001, by and between Second Imperial Geothermal Company QFID No. 3021 and Southern California Edison Company incorporated by reference to Exhibit 10.3.40 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.38   Agreement Addressing Renewable Energy Pricing and Payment Issues, dated June 15, 2001, by and between Heber Geothermal Company QFID No. 3001 and Southern California Edison Company incorporated by reference to Exhibit 10.3.41 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.39   Amendment No. 1 to Agreement Addressing Renewable Energy Pricing and Payment Issues, dated November 30, 2001, by and between Heber Geothermal Company QFID No. 3001 and Southern California Edison Company incorporated by reference to Exhibit 10.3.42 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.40   Energy Services Agreement, dated February 2003, by and between Imperial Irrigation District and ORMESA, LLC incorporated by reference to Exhibit 10.3.43 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.41   Purchase Power Contract, dated March 24, 1986, by and between Hawaii Electric Light Company and Thermal Power Company incorporated by reference to Exhibit 10.3.44 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.42   Firm Capacity Amendment to Purchase Power Contract, dated July 28, 1989, by and between Hawaii Electric Light Company and Puma Geothermal Venture incorporated by reference to Exhibit 10.3.45 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.43   Amendment to Purchase Power Contract, dated October 19, 1993, by and between Hawaii Electric Light Company and Puma Geothermal Venture incorporated by reference to Exhibit 10.3.46 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.44   Third Amendment to the Purchase Power Contract, dated March 7, 1995, by and between Hawaii Electric Light Company and Puna Geothermal Venture incorporated by reference to Exhibit 10.3.47 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.45   Performance Agreement and Fourth Amendment to the Purchase Power Contract, dated February 12, 1996, by and between Hawaii Electric Light Company and Puna Geothermal Venture incorporated by reference to Exhibit 10.3.48 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .2.46   Agreement to Design 69 KV Transmission Lines, a Substation at Pohoiki, Modifications to Substations at Puna and Kaumana, and a Temporary 34.5 Facility to Interconnect PGV’s Geothermal Electric Plant with HELCO’s System Grid (Phase II and III), dated June 7, 1990, by and between Hawaii Electric Light Company and Puna Geothermal Venture incorporated by reference to Exhibit 10.3.49 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.


191


 

         
Exhibit
   
No.   Document
 
  10 .3.1   Ormesa BLM Geothermal Resources Lease CA 966 incorporated by reference to Exhibit 10.4.1 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .3.2   Ormesa BLM License for Electric Power Plant Site CA 24678 incorporated by reference to Exhibit 10.4.2 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .3.3   Geothermal Resources Mining Lease, dated February 20, 1981, by and between the State of Hawaii, as Lessor, and Kapoho Land Partnership, as Lessee incorporated by reference to Exhibit 10.4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .3.4   Geothermal Lease Agreement, dated October 20, 1975, by and between Ruth Walker Cox and Betty M. Smith, as Lessor, and Gulf Oil Corporation, as Lessee incorporated by reference to Exhibit 10.4.4 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .3.5   Geothermal Lease Agreement, dated August 1, 1976, by and between Southern Pacific Land Company, as Lessor, and Phillips Petroleum Company, as Lessee incorporated by reference to Exhibit 10.4.5 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .3.6   Geothermal Resources Lease, dated November 18, 1983, by and between Sierra Pacific Power Company, as Lessor, and Geothermal Development Associates, as Lessee incorporated by reference to Exhibit 10.4.6 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .3.7   Lease Agreement, dated November 1, 1969, by and between Chrisman B. Jackson and Sharon Jackson, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.7 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  10 .3.8   Lease Agreement, dated September 22, 1976, by and between El Toro Land & Cattle Co., as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.8 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  10 .3.9   Lease Agreement, dated February 17, 1977, by and between Joseph L. Holtz, as Lessor, and Chevron U.S.A. Inc., as Lessee incorporated by reference to Exhibit 10.4.9 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  10 .3.10   Lease Agreement, dated March 11, 1964, by and between John D. Jackson and Frances Jones Jackson, also known as Frances J. Jackson, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.10 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  10 .3.11   Lease Agreement, dated February 16, 1964, by and between John D. Jackson, conservator for the estate of Aphia Jackson Wallan, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.11 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  10 .3.12   Lease Agreement, dated March 17, 1964, by and between Helen S. Fugate, a widow, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.12 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .3.13   Lease Agreement, dated February 16, 1964, by and between John D. Jackson and Frances J. Jackson, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.13 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.


192


 

         
Exhibit
   
No.   Document
 
  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.
  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.


193


 

         
Exhibit
   
No.   Document
 
  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.
  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.


194


 

         
Exhibit
   
No.   Document
 
  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.
  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.


195


 

         
Exhibit
   
No.   Document
 
  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.
  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.


196


 

         
Exhibit
   
No.   Document
 
  10 .19   Amendment No. 2 to the Power Purchase Contract between Ormesa LLC and Ormat Technologies, Inc., and Southern California Edison Company (RAP ID 3012) dated April 23, 2006, incorporated by reference to Exhibit 10.21.2 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on August 8, 2007.
  10 .20   Joint Ownership Agreement for the Carson Lake Project, dated as of March 12, 2008, by and between Nevada Power Company and ORNI 16 LLC, incorporated by reference to Exhibit 10.24 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on May 7, 2008.
  10 .21   Note Purchase Agreement, dated as of May 18, 2009, among Ortitlan, Limitada and TCW Global Project Fund II, Ltd., incorporated by reference to Exhibit 10.23 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on May 21, 2009.
  10 .22   Sale and Purchase Agreement dated August 2, 2010, between ORNI 44 LLC and CD Mammoth Lakes I, Inc. and CD Mammoth Lakes II, Inc., incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on November 4, 2010.
  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.


197


 

 
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: February 28, 2011
 
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 February 28, 2011.
 
         
    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


198


 

  (c)   EXHIBIT INDEX
 
         
Exhibit
   
No.   Document
 
  3 .1   Second Amended and Restated Certificate of Incorporation, incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  3 .2   Third Amended and Restated By-laws, incorporated by reference to Exhibit 3.2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 26, 2009.
  3 .3   Amended and Restated Limited Liability Company Agreement of OPC LLC dated June 7, 2007, by and among Ormat Nevada Inc., Morgan Stanley Geothermal LLC, and Lehman-OPC LLC, incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on June 13, 2007.
  4 .1   Form of Common Share Stock Certificate, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  4 .2   Form of Preferred Share Stock Certificate, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  4 .3   Form of Rights Agreement by and between Ormat Technologies, Inc. and American Stock Transfer & Trust Company, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.
  4 .4   Indenture for Senior Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.
  4 .5   Indenture for Subordinated Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.
  4 .6   Deed of Trust, dated as of August 3, 2010, between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 2, 2011.
  4 .7   Addendum, dated as of January 27, 2011, to the Deed of Trust, dated as of August 3, 2010, between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 2, 2011.
  4 .8   Form of Bond issued pursuant to the Deed of Trust, dated as of August 3, 2010 (as amended or supplemented), between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 2, 2011.
  10 .1.1   Indenture, dated February 13, 2004, among Ormat Funding Corp., Brady Power Partners, Steamboat Development Corp., Steamboat Geothermal LLC, OrMammoth Inc., ORNI 1 LLC, ORNI 2 LLC, ORNI 7 LLC, Ormesa LLC and Union Bank of California, incorporated by reference to Exhibit 10.1.7 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .1.2   First Supplemental Indenture, dated May 14, 2004, among Ormat Funding Corp., Brady Power Partners, Steamboat Development Corp., Steamboat Geothermal LLC, OrMammoth Inc., ORNI 1 LLC, ORNI 2 LLC, ORNI 7 LLC, Ormesa LLC and Union Bank of California, incorporated by reference to Exhibit 10.1.8 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.


199


 

         
Exhibit
   
No.   Document
 
  10 .1.3   Fifth Supplemental Indenture, dated April 26, 2006, among Ormat Funding Corp. and Union Bank of California, N.A., incorporated by reference to Exhibit 10.1.6 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q (File No 001-32347) to the Securities and Exchange Commission on August 7, 2006.
  10 .1.4   Loan Agreement, dated October 1, 2003, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.9 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .1.5   Amendment No. 1 to Loan Agreement, dated September 20, 2004, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.10 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .1.6   Guarantee Fee Agreement, dated January 1, 1999, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.13 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .1.7   Reimbursement Agreement, dated July 15, 2004, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.14 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .1.8   Services Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd., incorporated by reference to Exhibit 10.1.15 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .1.9   Agreement for Purchase of Membership Interests in OPC LLC dated June 7, 2007, by and among Ormat Nevada Inc., Morgan Stanley Geothermal LLC and Lehman-OPC LLC, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on June 13, 2007.
  10 .1.10   First Amendment to Agreement for Purchase of Membership Interests in OPC LLC, dated as of April 17, 2008, by and among Ormat Nevada Inc., Morgan Stanley Geothermal LLC, and Lehman-OPC LLC, incorporated by reference to Exhibit 10.1.18 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on May 7, 2008.
  10 .1.11   Membership Interest Purchase Agreement, dated as of October 30, 2009, by and among Lehman-OPC LLC, Ormat Nevada Inc. and OPC LLC, incorporated by reference to Exhibit 10.1.13 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on November 3, 2009.
  10 .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.


200


 

         
Exhibit
   
No.   Document
 
  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.
  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.


201


 

         
Exhibit
   
No.   Document
 
  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.
  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.


202


 

         
Exhibit
   
No.   Document
 
  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
  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.


203


 

         
Exhibit
   
No.   Document
 
  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.
  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.


204


 

         
Exhibit
   
No.   Document
 
  10 .3.10   Lease Agreement, dated March 11, 1964, by and between John D. Jackson and Frances Jones Jackson, also known as Frances J. Jackson, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.10 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  10 .3.11   Lease Agreement, dated February 16, 1964, by and between John D. Jackson, conservator for the estate of Aphia Jackson Wallan, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.11 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  10 .3.12   Lease Agreement, dated March 17, 1964, by and between Helen S. Fugate, a widow, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.12 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .3.13   Lease Agreement, dated February 16, 1964, by and between John D. Jackson and Frances J. Jackson, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.13 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .3.14   Lease Agreement, dated February 20, 1964, by and between John A. Straub and Edith D. Straub, also known as John A. Straub and Edythe D. Straub, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.14 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  10 .3.15   Lease Agreement, dated July 1, 1971, by and between Marie L. Gisler and Harry R. Gisler, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.15 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  10 .3.16   Lease Agreement, dated February 28, 1964, by and between Gus Kurupas and Guadalupe Kurupas, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.16 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004
  10 .3.17   Lease Agreement, dated April 7, 1972, by and between Nowlin Partnership, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.17 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  10 .3.18   Geothermal Lease Agreement, dated July 18, 1979, by and between Charles K. Corfman, an unmarried man as his sole and separate property, and Lessor, and Union Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.18 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  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.


205


 

         
Exhibit
   
No.   Document
 
  10 .3.21   Lease Agreement, dated May 13, 1971, by and between Mathew J. La Brucherie and Jane E. La Brucherie, husband and wife, and Robert T. O’Dell and Phyllis M. O’Dell, husband and wife, as Lessor, and Union Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.21 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  10 .3.22   Lease Agreement, dated June 2, 1971, by and between Dorothy Gisler, a widow, Joan C. Hill, and Jean C. Browning, as Lessor, and Union Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.22 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .3.23   Geothermal Lease Agreement, dated February 15, 1977, by and between Walter J. Holtz, as Lessor, and Magma Energy Inc., as Lessee incorporated by reference to Exhibit 10.4.23 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .3.24   Geothermal Lease, dated August 31, 1983, by and between Magma Energy Inc., as Lessor, and Holt Geothermal Company, as Lessee incorporated by reference to Exhibit 10.4.24 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .3.25   Unprotected Lease Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd. incorporated by reference to Exhibit 10.4.25 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
  10 .3.26   Geothermal Resources Lease, dated June 27, 1988, by and between Bernice Guisti, Judith Harvey and Karen Thompson, Trustees and Beneficiaries of the Guisti Trust, as Lessor, and Far West Capital, Inc., as Lessee incorporated by reference to Exhibit 10.4.26 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .3.27   Amendment to Geothermal Resources Lease, dated January, 1992, by and between Bernice Guisti, Judith Harvey and Karen Thompson, Trustees and Beneficiaries of the Guisti Trust, as Lessor, and Far West Capital, Inc., as Lessee incorporated by reference to Exhibit 10.4.27 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .3.28   Second Amendment to Geothermal Resources Lease, dated June 25, 1993, by and between Bernice Guisti, Judith Harvey and Karen Thompson, Trustees and Beneficiaries of the Guisti Trust, as Lessor, and Far West Capital, Inc. and its Assignee, Steamboat Development Corp., as Lessee incorporated by reference to Exhibit 10.4.28 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .3.29   Geothermal Resources Sublease, dated May 31, 1991, by and between Fleetwood Corporation, as Lessor, and Far West Capital, Inc., as Lessee incorporated by reference to Exhibit 10.4.29 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  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.


206


 

         
Exhibit
   
No.   Document
 
  10 .3.33   Participation Agreement, dated May 18, 2005, by and among Puna Geothermal Venture, SE Puna, L.L.C., Wilmington Trust Company, S.E. Puna Lease, L.L.C., AIG Annuity Insurance Company, American General Life Insurance Company, Allstate Life Insurance Company and Union Bank of California, incorporated by reference to Exhibit 10.4.33 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q/A to the Securities and Exchange Commission on December 22, 2005.
  10 .3.34   Project Lease Agreement, dated May 18, 2005, by and between SE Puna, L.L.C. and Puna Geothermal Venture, incorporated by reference to Exhibit 10.4.34 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q/A to the Securities and Exchange Commission on December 22, 2005.
  10 .4.1   Patent License Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd. incorporated by reference to Exhibit 10.5.4 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
  10 .4.2   Form of Registration Rights Agreement by and between Ormat Technologies, Inc. and Ormat Industries Ltd. incorporated by reference to Exhibit 10.5.5 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.
  10 .5.1   Ormat Technologies, Inc. 2004 Incentive Compensation Plan incorporated by reference to Exhibit 10.6.1 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.
  10 .5.2   Form of Incentive Stock Option Agreement incorporated by reference to Exhibit 10.6.2 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.
  10 .5.3   Form of Nonqualified Stock Option Agreement incorporated by reference to Exhibit 10.6.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.
  10 .6   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.


207


 

         
Exhibit
   
No.   Document
 
  10 .11.1   Indenture dated as of December 8, 2005 among OrCal Geothermal Inc., OrHeber 1 Inc., OrHeber 2 Inc., Second Imperial Geothermal Company, Heber Field Company and Heber Geothermal Company and Union Bank of California, incorporated by reference to Exhibit 10.13 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 28, 2006.
  10 .11.2   First Supplemental Indenture dated as of June 14, 2006 amending the Indenture dated as of December 8, 2005 among OrCal Geothermal Inc., OrHeber 1 Inc., OrHeber 2 Inc., Second Imperial Geothermal Company, Heber Field Company and Heber Geothermal Company and Union Bank of California, incorporated by reference to Exhibit 10.13.2 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q (File No 001-32347) to the Securities and Exchange Commission on August 7, 2006.
  10 .12   Guarantee dated as of December 8, 2005 among OrCal Geothermal Inc., OrHeber 1 Inc., OrHeber 2 Inc., Second Imperial Geothermal Company, Heber Field Company and Heber Geothermal Company, incorporated by reference to Exhibit 10.14 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 28, 2006.
  10 .13   Note Purchase Agreement, dated February 6, 2004, among Lehman Brothers Inc., Ormat Funding Corp., Brady Power Partners, Steamboat Geothermal LLC, OrMammoth Inc., ORNI 1 LLC, ORNI 2 LLC and ORNI 7 LLC, incorporated by reference to Exhibit 10.15 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on March 28, 2006.
  10 .14   Agreement No. 2 Addressing Renewable Energy Pricing Issues, dated May 10, 2006, between Ormesa LLC and Southern California Edison Company, incorporated by reference to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on May 16, 2006.
  10 .15   Agreement No. 2 Addressing Renewable Energy Pricing Issues, dated May 10, 2006, between Ormesa LLC and Southern California Edison Company, incorporated by reference to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on May 16, 2006.
  10 .16   Agreement No. 2 Addressing Renewable Energy Pricing Issues, dated May 10, 2006, between Heber Geothermal Company and Southern California Edison Company, incorporated by reference to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on May 16, 2006.
  10 .17   Agreement No. 2 Addressing Renewable Energy Pricing Issues, dated May 10, 2006, between Second Imperial Geothermal Company and Southern California Edison Company, incorporated by reference to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on May 16, 2006.
  10 .18.1   Amended and Restated Power Purchase Agreement for Olkaria III Geothermal Plant, dated January 19, 2007, between OrPower 4 Inc. and The Kenya Power and Lighting Company Limited, incorporated by reference to Ormat Technologies, Inc. Annual Report o Form 10-K to the Securities and Exchange Commission on March 12, 2007.
  10 .18.2   Olkaria III Project Security Agreement, dated January 19, 2007, between OrPower 4 Inc. and The Kenya Power and Lighting Company Limited, incorporated by reference to Ormat Technologies, Inc. Annual Report o Form 10-K to the Securities and Exchange Commission on March 12, 2007.
  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.


208


 

         
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   Joint Ownership Agreement for the Carson Lake Project, dated as of March 12, 2008, by and between Nevada Power Company and ORNI 16 LLC, incorporated by reference to Exhibit 10.24 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on May 7, 2008.
  10 .21   Note Purchase Agreement, dated as of May 18, 2009, among Ortitlan, Limitada and TCW Global Project Fund II, Ltd., incorporated by reference to Exhibit 10.23 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on May 21, 2009.
  10 .22   Sale and Purchase Agreement dated August 2, 2010, between ORNI 44 LLC and CD Mammoth Lakes I, Inc. and CD Mammoth Lakes II, Inc., incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on November 4, 2010.
  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.


209