ORMAT TECHNOLOGIES, INC. (Form: 10-K, Received: 03/12/2007 06:15:30)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2006


	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, Suite 300, 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 No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

Yes No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of ‘‘accelerated filer and large accelerated filer’’ in Rule 12b-2 of the Exchange Act.

Large accelerated filer Accelerated filer Non-accelerated filer

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

As of June 30, 2006, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $426,858,875 based on the closing price as reported on the New York Stock Exchange.

The number of outstanding shares of common stock of Ormat Technologies, Inc., as of February 28, 2007, was 38,111,108 par value $0.001 per share.

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, 2006.

ORMAT TECHNOLOGIES, INC.

FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2006

TABLE OF CONTENTS [to update page #]


		Page No.
PART I
ITEM 1.	BUSINESS		5
ITEM 1A.	RISK FACTORS		44
ITEM 1B.	UNRESOLVED STAFF COMMENTS		60
ITEM 2.	PROPERTIES		60
ITEM 3.	LEGAL PROCEEDINGS		60
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		62
PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		63
ITEM 6.	SELECTED FINANCIAL DATA		64
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		67
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		96
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		97
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		175
ITEM 9A.	CONTROLS AND PROCEDURES		175
ITEM 9B.	OTHER INFORMATION		176
PART III
ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE		177
ITEM 11.	EXECUTIVE COMPENSATION		181
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		181
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE		181
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES		181
PART IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES		181
SIGNATURES			197

Table of Contents

Cautionary Note Regarding Forward-Looking Statements

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

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


	•	significant considerations and risks 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);


	•	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;


	•	financial market conditions and the results of financing efforts;


	•	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 power purchase agreements for our projects;


	•	contract counterparty risk;


	•	weather and other natural phenomena;


	•	the impact of recent and future federal, state and local regulatory proceedings and changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and incentives for the production of renewable energy in the United States and elsewhere, changes in environmental and other laws and regulations to which our company is subject, as well as changes in the application of existing laws and regulations;


	•	current and future litigation;


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

Table of Contents


	•	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; and,


	•	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.

Table of Contents

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. The ‘‘OFC Senior Secured Notes’’ refers to the 8¼% Senior Secured Notes due 2020 that were issued in February 2004 by our subsidiary, Ormat Funding Corp. The ‘‘OrCal Senior Secured Notes’’ refers to the 6.21% Senior Secured Notes due 2020 that were issued in December 2005 by our subsidiary, OrCal Geothermal Inc.

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, in each case using equipment that we design and manufacture. We conduct our business activities in two business segments. 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 Products 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.

Most of the projects 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 have developed and continue to develop products that produce electricity from recovered energy or so-called ‘‘waste heat.’’ We also own and are constructing new recovered energy projects to be owned and operated by us. Recovered energy or waste heat represents residual heat that is generated as a by-product of gas turbine-driven compressor stations and a variety of industrial processes, such as cement manufacturing, and is not otherwise used for any purpose. Such residual heat, that 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 emissions.

Company Contact and Sources of Information

We file annual, quarterly and periodic reports, proxy statements and other information with the Securities and Exchange Commission, which we refer to as 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., 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.

On May 31, 2006, we submitted to the New York Stock Exchange (NYSE) an Annual Written Affirmation, in the prescribed form and with no qualifications, regarding our compliance with the

Table of Contents

NYSE’s Corporate Governance listing standards. In addition, our reports on Form 10-K, 10-Q and 8-K, and amendments to those reports are available at our website www.ormat.com for downloading, free of charge, as soon as reasonably practicable after these reports are filed with the SEC. Our Code of Business Conduct and Ethics, Code of Ethics Applicable to Senior Executives, Audit Committee Charter, Corporate Governance Guidelines, Nominating and Corporate Governance Committee Charter, Compensation Committee Charter, and Insider Trading Policy, as amended, are also available at our website address mentioned above . The content of our website, however, is not part of this annual report.

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

Our Power Generation Business

We own or control, and operate geothermal and recovered energy projects in the United States. We also own or control, and operate geothermal projects in Guatemala, Kenya, Nicaragua, and the Philippines. We continue to pursue opportunities to acquire and develop similar projects throughout the world. Most of our projects are located in regions where there is, or is expected to be, demand for additional generating capacity. We increased our net ownership interest in generating capacity by 51 megawatts (MW) between December 31, 2005 and December 31, 2006, resulting from the following: An increase of 19 MW, attributable to the acquisition of an additional 79.0% ownership interest in the Zunil project in Guatemala; an increase of 22 MW, attributable to the construction of the OREG 1 recovered energy project; an increase of 6 MW, attributable to the Gould geothermal power plant; and an increase of 5 MW, attributable to increased generating capacity of our existing geothermal power plants resulting from improvements to the geothermal well fields of some of our existing projects. We experienced a 1 MW reduction in generating capacity at our Brady project as a result of cooling. During the fourth quarter of 2006, we completed the construction of the Desert Peak 2 project in Nevada, which added 12 MW to our generating capacity. We have not yet declared this project commercially operational, which would trigger our obligation to provide the contracted generating capacity under the power purchase agreement.

In the year ended December 31, 2006, revenues from our electricity segment were $195.5 million, constituting approximately 72.7% of our total revenues in 2006. Revenues from the sale of electricity by our domestic projects were $162.8 million, constituting approximately 83.3% of our total revenues from the sale of electricity, and revenues from the sale of electricity by our foreign projects were $32.6 million, constituting approximately 16.7% of our total revenues from the sale of electricity.

The table below summarizes key information relating to our projects that are in operation as of December 31, 2006:

Table of Contents

Projects in Operation


Project	Location	Ownership ⁽¹⁾			Generating Capacity in MW ⁽²⁾		Power Purchaser	Contracts Expiration
Domestic
Ormesa Complex	East Mesa, California		100	%		47	Southern California Edison Company	2017/2018
Heber Complex ⁽³⁾	Heber, California		100	%		82	Southern California Edison Company and Southern California Public Power Authority	2015/2023/2031
Steamboat Complex ⁽⁴⁾	Steamboat, Nevada		100	%		53	Sierra Pacific Power Company	2007 ⁽⁵⁾ /2018/2022/2026
Mammoth Complex	Mammoth Lakes, California		50	%		29	Southern California Edison Company	2014/2020
Puna	Puna, Hawaii		100	%		30	Hawaii Electric Light Company	2027
Brady	Churchill County, Nevada		100	%		19	Sierra Pacific Power Company	2022
Desert Peak 2 ⁽⁶⁾	Churchill County, Nevada		100	%		12	Nevada Power Company	2027
OREG 1	North and South Dakota		100	%		22	Basin Electric Power Cooperative	2031
Total For Domestic Projects in Operation:						294
Foreign
Leyte ⁽⁷⁾	Philippines		80	%		49	PNOC – Energy Development Corporation	2007
Momotombo	Nicaragua		100	%		30	DISNORTE/DISSUR	2014
Zunil	Guatemala		100	%		24	Instituto Nacional de Electricidad	2019
Olkaria III (Phase I)	Kenya		100	%		13	Kenya Power and Lighting Co. Ltd.	2020 ⁽⁸⁾
Total For Foreign Projects in Operation:						116
Total For Projects in Operation:						410


⁽¹⁾	We own and operate all of our projects, except the Momotombo project in Nicaragua, which we do not own but which we control and operate through a concession arrangement with the Nicaraguan government, and the Mammoth and Leyte projects, in which we have a 50% and 80% ownership interest, respectively.

⁽²⁾

References to generating capacity refers to the gross capacity less auxiliary power, in the case of all of our existing domestic projects and the Momotombo and Olkaria III projects (two of our foreign projects), and to the generating capacity that is subject to the ‘‘take or pay’’ power purchase agreements in the case of the Leyte and Zunil projects (another two of our foreign projects). We determine the generating capacity figures in any given year from available historical operational data of our operating projects taking into account resource capabilities. This column represents the generating capacity of the project, not our net ownership in such generating capacity.

In any given year, the actual power generation of a particular project may differ from that project’s generating capacity due to operational issues affecting performance during that year. In 2006, the total actual power generation of the projects we operate in the U.S. was 1,998,660 MWh lower than the energy potential commensurate with our generating capacity due to operational factors discussed elsewhere in this annual report.


⁽³⁾	The Heber Complex includes the Heber 1 and 2 projects and the Gould project.


⁽⁴⁾	The Steamboat Complex includes the Steamboat 1 and 1A projects, the Steamboat 2 and 3 projects, the Burdette project and the Steamboat Hills project. The Galena 2 project, which is currently in final completion tests, will be added to the Steamboat Complex.


⁽⁵⁾	The initial term of the power purchase agreement expired on December 31, 2006, but is being renewed automatically on an annual basis.

Table of Contents


⁽⁶⁾	We have completed construction in the fourth quarter of 2006, but have not yet declared commercial operation under the power purchase agreement.


⁽⁷⁾	The Leyte project will be transferred to the power purchasing utility in September 2007 for no consideration. This will reduce our foreign generation capacity by 49 MW.


⁽⁸⁾	The power purchase agreement for the Olkaria III project will expire in 2020 or, if Phase II of the project is constructed and completed, 20 years from the completion of such Phase II. Phase II of this project involves the construction of additional facilities that we expect would add approximately 35 MW of generating capacity to this project. See ‘‘Description of our Projects’’ below.

The tables below summarize key information relating to the projects that are currently under construction and under development:

Projects under Construction


Project	Location	Ownership			Projected Commercial Operation Date	Projected Generating Capacity in (MW)		Power Purchaser	Contract Expiration
Steamboat Complex ⁽¹⁾	Washoe County, Nevada		100	%	2007		14	Nevada Power Company/Sierra Pacific Power Company	2018/2027
Ormesa	East Mesa, California		100	%	2007		10	Southern California Edison Company ⁽²⁾	N/A
Amatitlan ⁽³⁾	Guatemala		100	%	2007		20	Instituto Nacional De Electricidad	2026
Heber South	East Mesa, California		100	%	2007/2008		10	N/A	N/A
Puna	Puna, Hawaii		100	%	2007/2008		8	N/A	N/A
Galena 3	Nevada		100	%	2007/2008		17	Sierra Pacific Power Company	20 years following commercial operation date
OrSumas	Washington State		100	%	2007/2008		5	Puget Sound Energy	20 years from Jan. 1st following commercial operation date
Brawley (Phase I)	Imperial County, California		100	%	2008		50	N/A	N/A
Olkaria III (Phase II)	Kenya		100	%	2008		35	Kenya Power and Lighting Co.	N/A ⁽⁴⁾
Total							169


⁽¹⁾	The new construction in the Steamboat Complex includes the 4 MW Steamboat Hills project and the 10 MW Galena 2 project.


⁽²⁾	We have entered into an interim agreement with Southern California Edison Company and are currently negotiating a long-term power purchase agreement. See ‘‘Description of our Projects’’ below.


⁽³⁾	We have completed construction in the fourth quarter of 2006, but have not yet declared commercial operation.


⁽⁴⁾	The power purchase agreement for the Olkaria III Phase II project will expire 20 years from the completion of Phase II.

Table of Contents

Projects under Development

Project

Location

Ownership

Projected
Commercial
Operation Date

Projected
Generating
Capacity in
(MW)

Power
Purchaser

Contract Expiration

Carson Lake

Nevada

100

2009

18 - 30

Nevada Power Company

20 years following commercial operation date

Buffalo Valley

Nevada

100

2009

18 - 30

Nevada Power Company

20 years following commercial operation date

Brawley (Phase II)

Imperial

100

2009

N/A

County,

California

OREG II

100

2008/2009

27.5

Basin Electric Power Cooperative

N/A

Total

113.5 - 137.5

Almost all of the revenues that we currently derive from the sale of electricity are pursuant to long-term power purchase agreements. Approximately 74.4% of our total revenues in the year ended December 31, 2006 from the sale of electricity by our domestic projects were derived from power purchasers that currently have investment grade credit rating. The purchasers of electricity from our foreign projects are either state-owned entities or private entities. We have obtained political risk insurance from the Multilateral Investment Guarantee Agency of the World Bank Group (MIGA) or from Zurich Re, a private sector political risk insurer, for all of our foreign projects (other than the Leyte project) in order to cover a portion of any loss that we may suffer upon the occurrence of certain political events covered by such insurance.

Development, Construction and Acquisition. We have experienced significant growth in recent years, principally through the acquisition of geothermal power plants from third parties and the expansion and enhancement of our existing projects, including the following: (i) during 2006 we completed the acquisition of an additional 79.0% ownership interest in the Zunil project in Guatemala which increased our ownership capacity by 19 MW, (ii) during the third quarter of 2006 we completed the construction of the Gould project, which added 6 MW to the Heber complex; (iii) in October 2006, we completed the construction of the first owned recovered energy power plant, OREG 1, which added 22 MW to our generating capacity; and (iv) during the third quarter of 2006 we completed the enhancement program at the Mammoth and Momotombo projects, which added 5 MW to our generating capacity. We currently expect to continue growing our power generation business through:


	•	the development and construction of new geothermal and recovered energy-based power plants;


	•	the expansion and enhancement of our existing projects;


	•	the acquisition of additional geothermal and other renewable assets from third parties; and


	•	the entry into geothermal leases for future development.

As part of these efforts, we regularly monitor requests for proposals from, and submit bids to, investor-owned and other electric utilities in the United States to provide additional generating capacity, primarily in the western United States where geothermal resources are generally concentrated. During the third quarter of 2006, we responded to several requests for proposals issued by different utilities interested in purchasing renewable energy and we have been informed that some of our proposals, covering approximately 150 MW of proposed capacity in Nevada, California and Idaho, have been short-listed for further evaluation. There can be no assurance, however, that we will be chosen from the short list or that we will succeed in negotiating power purchase agreements with the various utilities. We also respond to international tenders issued by foreign state-owned electric

Table of Contents

utilities for the development, construction and operation of new geothermal power plants. In addition, we apply our technological expertise to upgrade the facilities of our existing geothermal power plants and to continuously monitor and manage our existing geothermal resources in order to increase the efficiency and generating capacity of such facilities.

We are currently in varying stages of development of new projects and construction of new and existing projects. Based on our current development and construction schedule, which is subject to change at any time and which may not be met in its entirety, we expect to declare commercial operation of the 12 MW Desert Peak 2 project during the first half of 2007 and we expect to add between 227 to 251 MW in generating capacity from geothermal and recovered energy power plants in the United States by the end of 2009. Outside of the U.S., we expect to declare commercial operation of the 20 MW Amatitlan project in Guatemala, during the first half of 2007, and to complete the construction of the 35 MW project in Kenya by the end of 2008.

We are a member in a consortium, which is in the process of developing a geothermal power project in Indonesia of approximately 300 MW that is expected to come on line in phases between 2010 and 2012. The consortium is currently negotiating a power purchase agreement with a local utility. We estimate that our minority interest equivalent will range between 45 MW to 60 MW.

Our Products Business

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

Power Units for Geothermal Power Plants. We design, manufacture and sell power units for geothermal electricity generation, which we refer to as Ormat Energy Converters or ‘‘OEC’’s. Our customers include contractors and geothermal plant owners and operators. We recently sold one of our air-cooled OEC units to Tauropaki Power Company of New Zealand

Engineering, Procurement and Construction (EPC) of Power Plants. We engineer, procure and construct, as an EPC contractor, geothermal and recovered energy power plants on a turnkey basis, using power units we design and manufacture. Our customers are geothermal power plant owners as well as the same customers described above that we target for the sale of our power units for recovered energy-based power generation. Unlike many other companies that provide EPC services, we have an advantage in that we are using our own manufactured equipment and thus have better control over the timing and delivery of required equipment and its costs. Recent examples of our construction activities include the design and construction of the Alliance REG plants in Canada and the Ngawha geothermal power plant in New Zealand.

In the year ended December 31, 2006, our revenues from our products business were $73.5 million, constituting approximately 27.3% of our total revenues.

Table of Contents

History

We were formed by Ormat Industries Ltd. (also referred to in this annual report as the ‘‘Parent,’’ ‘‘Ormat Industries,’’ ‘‘the parent company’’ or ‘‘our parent’’) in 1994 in the State of Delaware for the purpose of investing and holding ownership interests in power projects, as well as constructing and operating power plants owned by us and by third parties. Ormat Industries, which is based in Israel, is an international power systems company whose predecessor, Ormat Turbines Ltd., was founded in 1965 by Lucien and Dita Bronicki for the principal purpose of developing equipment for the production of a clean, renewable and generally sustainable form of energy. Ormat Industries sold to us its business relating to the manufacturing and sale of energy-related equipment and services. Following this sale, we now hold all of Ormat Industries’ power generation products business. Ormat Industries owns 64% of our outstanding common stock.

Industry Background

Geothermal Energy

Most of our projects in operation produce electricity from geothermal energy. Geothermal energy is a clean, renewable and generally sustainable energy source that, because it does not utilize combustion in the production of electricity, releases significantly lower levels of emissions, principally steam, than those that result from energy generation based on the burning of fossil fuels. Geothermal energy is derived from the natural heat of the earth when water comes sufficiently close to hot molten 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 projects 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.

Geothermal Power Plant Technologies

Geothermal power plants generally employ either binary systems or conventional flash systems. In our projects, we also employ our proprietary technology of combined geothermal cycle systems. See ‘‘Our Technology’’.

Binary System

In a 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.

Table of Contents

Flash Design System

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

In some instances, the wells directly produce dry steam (the flashing occurring under ground). 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.

Table of Contents

Market Opportunity

The geothermal energy industry in the United States experienced significant growth in the 1970s and 1980s, followed by a period of consolidation of owners and operators of geothermal assets in the 1990s. The industry, once dominated by large oil companies and investor-owned electric utilities, now includes several independent power producers. During the 1990s, growth and development in the geothermal energy industry occurred primarily in foreign markets, and only minimal growth and development occurred in the United States. Since 2001, there has been renewed interest in geothermal energy in the United States as production costs for electricity generated from geothermal resources have become more competitive relative to fossil fuel-based electricity generation, due to the increasing cost of natural gas, and as legislative and regulatory incentives, such as state renewable portfolio standards, have become more prevalent.

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

A 2006 forecast of the Western Governors Association (WGA) projects the addition of geothermal installations with generating capacity of approximately 13,000 MW by 2025, out of which 5,600 MW is expected to be added by 2015. This forecast is based on existing, known geothermal resources and does not take into account any positive effects on generating capacity resulting from new technology, such as enhanced utilization of existing geothermal bases and engineered geothermal systems (according to the WGA, Geothermal Taskforce Report from January 2006).

In January 2007, the Massachusetts Institute of Technology published a study that projects a potential of 100,000 MW of generating capacity from geothermal power plants if the development of enhanced geothermal systems is successful.

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, Maine, Maryland, Massachusetts, Minnesota, Montana, Nevada, New Jersey, New Mexico, New York, Pennsylvania, Rhode Island, Texas, Vermont, Washington, Wisconsin and the District of Colombia have all adopted renewable portfolio standards, renewable portfolio goals, or other 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. Of these twenty-three states, fifteen states and the District of Columbia (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 projects are located) define geothermal resources as ‘‘renewables’’. A bill establishing renewable portfolio standards is currently before the Kansas legislature.

We believe that these legislative measures and initiatives present a significant market opportunity for us. For example, California generally requires that each investor-owned electric utility company operating within the state increase the amount of renewable generation in its resource mix by 2% per year so that 20% of its retail sales are procured from eligible renewable energy sources by 2010, ahead of the previous statutory mandated target of December 2017. Presently, approximately 11% of the electricity generated in California is derived from renewable resources (not counting hydroelectricity as renewable power). Nevada’s renewable portfolio standard requires each Nevada electric utility to obtain 9% of its annual energy requirements from renewable energy sources in 2007-2008, which requirement thereafter increases by 3% every two years until 2015, when 20% of such annual energy requirements must be provided from renewable energy sources or energy efficiency projects. At least three-quarters of the annual total requirements must come only from renewable energy projects.

Table of Contents

Hawaii’s renewable portfolio standard requires each Hawaiian electric utility to obtain 8% of its net electricity sales from renewable energy sources by December 31, 2005, 10% by December 31, 2010 and 20% by December 31, 2020.

In addition, a new Act was signed into law in California to reduce carbon emissions to 1990 levels by 2020, representing a twenty-five percent reduction in greenhouse gas emissions. To accomplish this, the Act provides a framework for greenhouse gas emissions reductions through the use of emissions control technologies and other cost-effective reduction strategies. One such strategy may involve the use of market-based trading of emissions rights that will allow some greenhouse gas sources to over-control their emissions and sell the rights to their surplus reductions to other sources for whom the cost of reducing emissions would be significantly more costly. Although programs under the Act will take some time to develop, its requirements, particularly the creation of a market-based trading mechanism to achieve compliance with emissions caps, should be highly advantageous to in-state energy generating sources that have low carbon emissions such as geothermal energy.

The federal government also encourages production of electricity from geothermal resources through certain tax subsidies. We are permitted to claim approximately 10% of the cost of each new geothermal power plant in the United States as an investment tax credit against our federal income taxes. Alternatively, we are permitted to claim a ‘‘production tax credit,’’ which in 2006 was 1.9 cents per kWh and which is adjusted annually for inflation. The production tax credit may be claimed on the electricity output of new geothermal power plants put into service by December 31, 2008. Credit may be claimed for ten years on the output from any new geothermal power plants put into service prior to December 31, 2008. The owner of the project must choose between the production tax credit and the 10% investment tax credit 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. Whether we claim the production tax credit or the investment credit, we are also permitted to depreciate most of the plant for tax purposes over five years on an accelerated basis, meaning that more of the cost may be deducted in the first few years than during the remainder of the depreciation period. If we claim the investment credit, our ‘‘tax base’’ in the plant that we can recover through depreciation must be reduced by half of the tax credit; if we claim a production tax credit, there is no reduction in the tax basis for depreciation.

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

The Kyoto Protocol entered into force on February 16, 2005, making the Protocol’s emission targets for the 2008 to 2012 period legally binding on the more than 30 developed countries, including the EU members, Russia, Japan, Canada, New Zealand, Norway and Switzerland, all of which have ratified the Protocol. We expect that the effect of the Kyoto Protocol will be to encourage renewable energy installation outside of the United States, as the United States has not ratified the Kyoto Protocol.

Outside of the United States, the majority of power generating capacity has historically been owned and controlled by governments. During the past decade, 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. For example, China, where we are currently trying to develop a project, has recently enacted a Renewable Energy Law (effective January 1, 2006) defining fiscal incentives, priority dispatching, preferential pricing and other supporting mechanisms, and has announced long-term targets for renewable energy capacity growth, including mandatory renewable portfolio standards for large generation utilities. Several Latin American countries have rural electrification programs and renewable energy programs. For example, Guatemala, where our Zunil and Amatitlan projects are located, approved in November 2003 a law

Table of Contents

which creates 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. 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 us to sell our remote power units and other products.

In addition to our geothermal power generation activities, we have also identified recovered energy-based power generation as a significant market opportunity for us in North America and the rest of the world. We are initially targeting the North American market, where we expect that recovered energy-based power generation will be derived principally from compressor stations along interstate pipelines, from midstream gas processing facilities, and from processing industries in general. Several states, as well as the federal government, have recognized the environmental benefits of recovered energy-based power generation. For example, Nevada, Connecticut, New Mexico and Hawaii allow electric utilities to include recovered energy-based power generation in calculating their compliance with renewable portfolio standards. 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. We believe that the European market has similar potential and we expect to leverage our early success in North America in order to expand into Europe and other markets worldwide. In North America alone, we estimate the potential total market for recovered energy-based generation to be approximately 1,000 MW.

Table of Contents

Competitive Strengths

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


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


	•	Baseload Generation. All of our geothermal power plants supply a part of the baseload capacity of the electric system in their respective markets, meaning that they operate to serve all or a part of the minimum power requirements of the electric system in such market on an around-the-clock basis. Because our projects supply a part of the baseload needs of the respective electric system and are only marginally weather dependent, 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 the 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 as compared to electricity generated from fossil fuels or other renewable sources under existing economic conditions and existing tax and regulatory regimes.

Growing Legislative Demand for Environmentally-Friendly Renewable Resource Assets. Most of our currently operating projects produce electricity from geothermal energy sources. Geothermal energy is a clean, renewable and generally sustainable energy source. 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. Such 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 power plants. Our intimate knowledge of the equipment that we use in our operations allows us to operate and maintain our projects 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 projects, 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.

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 20 years of industry experience.

Technological Innovation. We own or have rights to use approximately 70 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.

Table of Contents

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 Projects — continuously seeking out commercially exploitable geothermal resources, developing and constructing new geothermal and recovered energy-based power projects and entering into long-term power purchase agreements 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;


	•	Developing Recovered Energy Projects — establishing a first-to-market leadership position in recovered energy projects 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 Projects — increasing output from our existing geothermal power projects 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 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.

Operations of our Power Generation Segment

How We Own Our Power Plants. We customarily establish a separate subsidiary to own interests in each power plant. Our purpose in establishing a separate subsidiary for each plant is to ensure that the plant, and the revenues generated by it, will be the only source for repaying indebtedness, if any, incurred to finance the construction or the acquisition (or to refinance the acquisition) of the relevant plant. If we do not own all of the interest in a power plant, we enter into a shareholders agreement or a partnership agreement that governs the management of the specific subsidiary and our relationship with our partner in connection with our project. Our ability to transfer or sell our interest in certain projects may be restricted by certain purchase options or rights of first refusal in favor of our project partners or the project’s power purchasers and/or certain change of control and assignment restrictions in the underlying project and financing documents. All of our domestic projects, with the exception of the Puna project, which is an Exempt Wholesale Generator (EWG), are Qualifying Facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) and are eligible for regulatory exemptions from most provisions of the Federal Power Act (FPA) and certain state laws and regulations.

How We Obtain Development Sites and Geothermal Resources. For domestic projects, we either lease or own the sites on which our power plants are located. In our foreign projects, 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. A geothermal resource lease (or sublease) or a concession or other agreement 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 terms of the lease

Table of Contents

(or sublease) and concession agreement correspond to the terms of the relevant power purchase agreement. In certain other cases, we own the land where the geothermal resource is located, in which case there are no restrictions on its utilization.

How We Sell Electricity. In the United States, the purchasers of power from our projects are typically investor-owned electric utility companies. Outside of the United States, the purchaser is typically a state-owned utility or distribution company or a recently privatized state-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 power purchase agreements) for the sale of electricity or the conversion of geothermal resources into electricity. A project’s revenues under a power purchase agreement usually consist of two payments: energy payments and capacity payments (although our recent power purchase agreements provide for energy payments only). Energy payments are normally based on a project’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’’ costs (i.e., the costs the power purchaser would have incurred itself had it produced the power it is purchasing from third parties, such as us). Capacity payments are normally calculated based on the generating capacity or the declared capacity of a project available for delivery to the purchaser, regardless of the amount of electrical output actually produced or delivered. In addition, most of our domestic projects located in California are eligible for capacity bonus payments under the respective power purchase agreements upon reaching certain levels of generation.

How We Operate and Maintain Our Power Plants. We usually employ one of our subsidiaries, (Ormat Nevada Inc., for our domestic projects) 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 approach to plant management emphasizes the operational autonomy of our individual plant managers and staff to identify and resolve operations and maintenance issues at their respective projects; however, each project 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 project complex and provided by one operation and maintenance provider. This approach enables us to realize cost savings and enhances our ability to meet our project availability goals.

We currently operate and maintain approximately 410 MW of generating capacity (See Note (2) page 7 for an explanation of how we determine the generating capacity of our projects). Since our acquisitions in California, Hawaii and Nevada, as a result of our vertical integration, our proprietary technology and our operational and maintenance expertise, we have been successful in increasing the capacity, efficiency and performance of most of our acquired facilities and were able to use the staff required to operate these facilities more efficiently. For example, we have been able to increase the output of the Mammoth project by approximately 4 MW following its acquisition in December 2003. We have also increased the capacity of the Heber Complex by 13 MW (out of which 3 MW were used for auxiliary power).

Safety is a key area of concern to us. We believe that the most efficient and profitable performance of our projects 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 projects.

How We Finance Our Power Plants. Historically, we have funded our projects with a combination of non-recourse or limited recourse debt, lease financing, parent company loans and internally generated cash. Such leveraged financing permits the development of projects with a limited amount of equity contributions, but also increases the risk that a reduction in revenues could adversely affect a particular project’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.

Table of Contents

Non-recourse debt or lease financing refers to debt or lease arrangements involving debt repayments or lease payments that are made solely from the project’s revenues (rather than our revenues or revenues of any other project) and generally are secured by the project’s physical assets, major contracts and agreements, cash accounts and, in many cases, our ownership interest in that project affiliate. These forms of financing are referred to as ‘‘project financing.’’ Project financing transactions generally are structured so that all revenues of a project are deposited directly with a bank or other financial institution acting as escrow or security deposit agent. These funds then are payable in a specified order of priority set forth in the financing documents to ensure that, to the extent available, they are used first to 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 project affiliate owning the project 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 project may reduce the liquidity of our equity interest in that project because the interest is typically subject both to a pledge in favor of the project’s lenders securing the project’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 the project affiliate in the form of certain limited obligations and contingent liabilities. These obligations and contingent liabilities 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 project, distributions received by us from other projects 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 project may have direct recourse to us.

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. The policies are issued by entities which specialize in such policies, such as MIGA, and from private sector providers, such as Zurich Re, AIG and other such companies. To date, our political risk insurance contracts are with MIGA and Zurich Re. Such insurance policies cover, in general and 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 projects in operation except for the Leyte project.

Recent Developments


	•	In February 2007, the Nevada Public Utilities Commission approved two new 20-year power purchase agreements that two of our subsidiaries entered into on August 3, 2006 with Nevada Power Company, a subsidiary of Sierra Pacific Resources, for the sale of energy to be produced from the Carson Lake (near Fallon) and Buffalo Valley Power Plants, two new geothermal power plants to be built in Lander and Churchill Counties in northern Nevada. The Carson Lake and Buffalo Valley projects are both projected to come on line in late 2009. These new plants are expected to increase the total output supplied from us to Sierra Pacific Resources by between 36 and 60 MW.


	•	On January 31, 2007, we entered into two contracts with a combined value of $9.0 million with Enpower Green Energy Generation, Inc. for the supply of two OEC units for two REG plants to be located on the Duke Energy T South Pipeline System in British Columbia, Canada. The equipment is to be supplied within 13 to 14 months of February 27, 2007, the effective date of both contracts.

Table of Contents


	•	On January 19, 2007, our subsidiary developing the Olkaria III project entered into an Amended and Restated Power Purchase Agreement and a Project Security Agreement, with Kenya Power and Lighting Co. (KPLC), the Kenyan parastatal electricity transmission and distribution company, with respect to Phase II of the Olkaria III project. These agreements were executed after receipt of appropriate regulatory approvals from the Kenyan authorities. The construction of Phase II of the project is expected, upon completion, to add approximately 35 MW to the existing facility, bringing the project’s total capacity to approximately 48 MW. Following completion of Phase II, total anticipated annual revenues from the project will be approximately $32 million .


	•	In January 2007, one of our subsidiaries entered into a Power Purchase Option Agreement with Basin Electric Power Cooperative (Basin Electric) regarding five new Recovered Energy Generation (REG) Power Plants along the Northern Border Pipeline in the States of Montana, North Dakota and Minnesota. According to the Option Agreement, Basin Electric will work towards fulfilling certain conditions with the goal to confirm that it is ready to enter into a definitive 25-year power purchase agreement. These conditions include the interconnection and rights to the site on which the power plants will be constructed. We have already secured the rights to the waste heat for two of the new power plants and will continue to work towards obtaining the rights to the remaining three new power plants. The approval for construction of the new power plants is expected during 2007 after both parties have fulfilled their prerequisite obligations under the Power Purchase Option Agreement.


	•	In January 2007, two of our subsidiaries entered into supply and engineering, procurement and construction contracts with Ngawha Generation Ltd., a subsidiary of Top Energy Limited for a new geothermal power plant in Ngawha, New Zealand. The contracts are for a total of approximately $20 million, with construction of the power plant expected to be completed within 20 months from the contract date. Top Energy Limited is an environmentally friendly, local electricity network company in New Zealand.


	•	In December 2006, one of our subsidiaries entered into geothermal leases in the North Brawley known geothermal resource area in Imperial County, California. These geothermal leases secured 1,270 acres and we are in discussion with other land owners in this area to secure additional leases. We expect to begin drilling activity to explore the resource upon receipt of the necessary drilling permits, which we expect will be granted in the first half of 2007.


	•	On December 19, 2006, we completed a sale of 2,500,000 shares of common stock to Lehman Brothers in a block trade at a price of $37.50 per share, under a shelf registration statement filed in early 2006. Net proceeds to us, after deducting underwriting fees and commissions and estimated offering expenses associated with the offering, were approximately $92.5 million.


	•	In November 2006, the California Public Utilities Commission (CPUC) approved several five-year agreements entered into with Southern California Edison (SCE) in May and June 2006 establishing new renewable energy pricing for our existing power purchase aqgreements . These new agreements fix the energy rates payable by SCE for the five-year period beginning May 1, 2007 for our Ormesa, Heber 1, Heber 2 and Mammoth geothermal projects located in California. Under the new agreements, the geothermal energy produced by these projects will be sold at an average fixed energy rate of $62.74 per MWh, starting with a rate of $61.50 per MWh for the first year, with an annual escalation of 1% thereafter. The new agreements will come into effect when the current Renewable Energy Pricing Agreement terminates on April 30, 2007. The new average energy rate of $62.74 per MWh will replace the existing rate of $53.70 per MWh. The capacity payment and capacity bonus under the respective power purchase agreement for each of the projects remain unchanged.


	•	During the third quarter of 2006, one of our subsidiaries signed geothermal lease agreements for leases of surface, mineral and geothermal rights, some with the Bureau of Land

Table of Contents


		Management and some with private owners, for: (i) approximately 7,500 acres in the Fallon area in Nevada; (ii) approximately 3,200 acres in the Fireball Ridge area in Nevada; (iii) approximately 16,400 acres in Gabbs Valley, Nevada; and (iv) approximately 640 acres in the Wildhorse prospect in Nevada.


	•	In October 2006, one of our subsidiaries completed the OREG 1 project along the Northern Border Pipeline in North Dakota and South Dakota. The OREG 1 project consists of four Recovered Energy Generation (REG) plants owned and operated by us with a total generating capacity of approximately 22 MW. Bismarck-based Basin Electric will purchase energy produced by these plants under a 25-year long-term power purchase agreement, which was announced in 2005.


	•	During the third quarter of 2006, we responded to several requests for proposals issued by different utilities interested in purchasing renewable energy. Recently, we were informed that some of our bids covering approximately 150 MW of proposed capacity in Nevada, California and Idaho have been short-listed for further evaluation. There can be no assurance, however, that we will be chosen from the short list or that we will succeed in negotiating power purchase agreements with the various utilities.


	•	On August 16, 2006, we acquired from two parties an additional 28.2% partnership interest (27.34% on a fully diluted basis assuming the exercise of an option by a third party) in Orzunil I de Electricidad, Limitada (Orzunil), which owns the Zunil project in Guatemala, thereby increasing our 71.8% ownership interest (69.67% on a fully diluted basis assuming the exercise of an option by a third party) in the Zunil Project to 100% (97% on a fully diluted basis, assuming the exercise of an option by a third party). The total purchase price for both acquisitions was $7.4 million (including acquisition costs of approximately $0.9 million). These acquisitions follow our acquisition of a 50.8% partnership interest (49.28% on a fully diluted basis assuming the exercise of an option by a third party) in Orzunil on March 13, 2006, whereby our subsidiary increased its then existing 21.0% ownership interest in the Zunil Project to 71.8% (69.67% on a fully diluted basis assuming the exercise of an option by a third party). The purchase price we paid for the 50.8% acquisition was $15.4 million (including acquisition costs of approximately $0.6 million).


	•	In August 2006, the Nevada Public Utilities Commission approved the new 20-year power purchase agreement that our subsidiary entered into with Sierra Pacific Power Company in May 2006 for the sale of energy to be produced from the Galena 3 power plant, which is currently under construction. Under the new power purchase agreement, between 15 MW to 25 MW will be delivered from the Galena 3 project to SPPC for a fixed price of $61 per MWh, or $58 per MWh, assuming the project will be eligible for a production tax credit. These rates escalate at the beginning of each contract year by 1% and include the value of the renewable energy credits.


	•	In July 2006, a consortium consisting of our wholly owned subsidiary, a unit of Medco Energi Internasional Tbk (Indonesia’s largest private oil and gas company), and Itochu Corp. of Japan won a tender issued by the Indonesian state-owned utility PT PLN (Persero) for the development of the Sarulla, North Sumatra, Indonesia geothermal power project on an independent power producer basis. Medco is the leader of the consortium, whose bid consisted of the completion of the development of the geothermal steam field, construction of the field piping systems and three Ormat designed and supplied power plants with a combined gross capacity of 340 MW, owning and operating the facilities and selling electricity to PLN under a 30-year power purchase agreement expected to be concluded within four months. Our specific responsibilities include the supply of the power plant and setting up and supervising the operations and maintenance of the plants, which will utilize our technology and equipment. The total project cost is projected to be about $600 million. The value of our scope of work for the supply of power plant equipment is expected to be approximately one-third of the total project cost. Release of the supply contracts to us will be made upon the financial closing of the transaction, expected to be 12 months from the effective date of

Table of Contents


		the power purchase agreement. The Sarulla project is to be constructed over the next five years in three phases of 110 to 120 MW each, with the first power generating unit to be operational within 30 months and the last within 48 months from the financial closing. The project will be owned and operated by an Indonesian special purpose company (SPC) that will be established by the consortium members under the framework of a Joint Operating Contract with the concession holder, Pertamina (the state-owned oil and gas company). In addition to our responsibilities as the project’s power plant equipment supplier and supervisor of operations and maintenance, we will participate as a minority shareholder in the SPC.


	•	On July 26, 2006, we entered into a contract valued at $4.0 million with ENAGAS S.A. of Madrid, Spain, for the supply of one OEC unit for a REG plant located in the ENAGAS gas compression station at Almendralejo, Spain. The equipment is to be supplied and installed within 19 months from the date of the contract.


	•	On July 20, 2006, we entered into a contract valued at $4.4 million with Geo X GmbH of Ludwigshafen, Germany, for the supply of one OEC unit for a geothermal power plant located in Landau, Germany. The equipment is to be supplied and installed within 17 months from the date of the contract.


	•	On June 7, 2006, one of our wholly-owned subsidiaries received supply and construction orders for three REG power plants on the Alliance Pipeline. Each facility will have a capacity of 5 MW net and will convert the recovered waste heat from the exhaust of existing gas turbines into electricity. The contracts are in the total amount of $29.0 million. The three plants are expected to be commissioned in 2007 or early 2008.


	•	On April 26, 2006, we received a notice to proceed on an engineering, procurement and construction (EPC) contract to construct a geothermal power plant for the Raft River project in Idaho, for a total sales price of $20.2 million. Construction of the power plant is expected to be completed in the last quarter of 2007.


	•	On April 10, 2006, we completed a follow-on public offering of 3,500,000 shares of common stock at a price of $35.50 per share, under a shelf registration statement filed in early 2006. In addition, on April 17, 2006, the underwriters exercised their over-allotment option, thereby purchasing 525,000 additional shares of common stock at the same price. Net proceeds to us, after deducting underwriting fees and commissions and estimated offering expenses associated with the offering, were approximately $135.1 million.


	•	On April 4, 2006, we signed a contract to supply a 10 MW OEC power unit to PacifiCorp Energy in the Northwest region of the United States. The contract is in the amount of $11.5 million. The existing PacifiCorp plant, to which an additional OEC will be added, uses single-flash technology to produce approximately 23 MW of net power to the grid. The PacifiCorp plant utilizes only steam, which is separated from the brine and delivered to the plant, while the brine is reinjected into the ground. Ormat’s technology enables recovery of heat from the brine before reinjection and PacifiCorp Energy will utilize this new OEC power unit to generate 10 MW of additional power in the OEC without additional resources or wells. The OEC power unit will be delivered in the second quarter of 2007 for installation adjacent to the existing plant.

Description of Our Projects

In the year ended December 31, 2006, revenues from the sale of electricity by our domestic geothermal projects were $162.8 million, constituting 83.3% of our total revenues from the sale of electricity, and revenues from the sale of electricity by our foreign geothermal projects were $32.6 million, constituting 16.7% of our total revenues from the sale of electricity. During 2006 we began selling electricity from our recovered energy projects, whose construction was completed in 2006.

The financing of certain of our projects and the terms of our power purchase agreements and certain other agreements related to our operations are further described in the ‘‘Description of Certain Material Agreements’’ section.

Table of Contents

Domestic Projects

Our projects in operation in the United States have a generating capacity of approximately 294 MW. Our current domestic projects are located in California, Nevada, Hawaii, North Dakota, and South Dakota. We also have projects under construction or enhancement in California, Nevada and Hawaii.

The Ormesa Complex

The Ormesa complex is located in East Mesa, Imperial County, California. The Ormesa complex consists of six plants. The various plants commenced commercial operations between 1987 and 1989. The plants utilize binary and flash systems. The Ormesa complex has a generating capacity of 47 MW. Part of the electricity generated by two of the plants at the Ormesa complex, GEM 2 and GEM 3, is sold under an interim agreement (as discussed below) and part of it is used to provide auxiliary power for well field operations at the Ormesa complex. The Ormesa project sells its electrical output to Southern California Edison Company (Southern California Edison) under two separate power purchase agreements, which will expire in 2017 and 2018. We are currently in discussions with Southern California Edison to unitize the two power purchase agreements and to increase the amount of power being purchased by an additional 10 MW. The Ormesa project was acquired by us in April 2002, was initially refinanced with project finance debt from United Capital, and was refinanced again with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The OFC Senior Secured Notes are collateralized by all of the assets of the Ormesa project (and any and all proceeds arising therefrom) and our project subsidiary, Ormesa LLC, the direct owner of the Ormesa project, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed Ormat Funding’s obligations under the OFC Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the collateralization of the OFC Senior Secured Notes.

During 2006, we experienced a relatively high rate of well and pump failure at the Ormesa complex, resulting in increased operating costs and reduced revenues, and a lower availability of the Ormesa well field. As a result, we did not meet the required minimum capacity factor of 80% during the on-peak period for the months of June and September 2006. Consequently, we have been placed on probation for a period not to exceed 15 months. During the probation period, if we fail again to meet the minimum performance requirements, the capacity of the project may be permanently reduced, in which case Southern California Edison would be entitled to a refund. We believe that the risk of not meeting the minimum performance requirements during the probationary period and in the future is very low as we expect to increase the generating capacity of the Ormesa complex by 10 MW to a total of 57 MW by the end of the first quarter of 2007.

In connection with the power purchase agreements for the Ormesa complex, Southern California Edison has expressed its intent not to pay the contract rate for the power supplied by the GEM 2 and GEM 3 plants to the Ormesa complex. Southern California Edison contends that California ISO real-time prices should apply, while management believes that SP-15 prices quoted by NYMEX should apply. According to Southern California Edison’s estimation, the amount under dispute is approximately $2.5 million. The parties have signed an Interim Agreement, whereby Southern California Edison will continue to procure the GEM 2 and GEM 3 power at the current energy rate of 5.37 Cents/kWh until May 1, 2007. In addition, a long-term power purchase agreement is expected to be entered into for the GEM 2 and GEM 3 power. The negotiations of the long-term power purchase agreement are still under way and there is no guarantee that it will be successfully completed. Management believes that such settlement agreement will not have a material financial impact on us.

The Heber Complex

The Heber complex consists of the Heber 1 project, the Heber 2 project and the Gould project.

The Heber 1 Project. The Heber 1 project is located in Heber, Imperial County, California. The Heber 1 project includes one power plant, which commenced commercial operations in 1985, and a

Table of Contents

geothermal resource field. The plant utilizes a dual flash system and has a generating capacity of approximately 38 MW. The Heber 1 project sells its electrical output to Southern California Edison under a long-term power purchase agreement, which will expire in 2015. In certain circumstances, Southern California Edison and its affiliated entities have a right of first refusal to acquire the power plant. Upon satisfaction of certain conditions specified in the power purchase agreement and subject to receipt of requisite approvals and negotiations between the parties, our project subsidiary will have the right to demand that Southern California Edison purchase the power plant. The acquisition of the Heber 1 project in December 2003 was financed with equity and non-recourse debt from Beal Bank, and was refinanced with the proceeds from the issuance by OrCal Geothermal Inc. (OrCal) of its Senior Secured Notes on December 8, 2005. The OrCal Senior Secured Notes are collateralized by all of the assets of the Heber Complex (and any and all proceeds arising therefrom) and our project subsidiary, Heber Geothermal Company, the direct owner of the Heber 1 project, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed OrCal’s obligations under the OrCal Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the collateralization of the OrCal Senior Secured Notes.

The Heber 2 Project. The Heber 2 project is also located in Heber, Imperial County, California. The Heber 2 project includes one power plant which commenced commercial operations in 1993. The plant utilizes a binary system and has a generating capacity of approximately 34 MW. The Heber 2 project sells its electrical output to Southern California Edison under a long-term power purchase agreement, which will expire in 2023. The acquisition of the Heber 2 project in December 2003 was financed with equity and non-recourse debt from Beal Bank, and was refinanced with the proceeds from the issuance by OrCal of its Senior Secured Notes on December 8, 2005. The OrCal Senior Secured Notes are collateralized by all of the assets of the Heber Complex (and any and all proceeds arising therefrom) and our project subsidiary, Second Imperial Geothermal Company, the direct owner of the Heber 2 project, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed OrCal’s obligations under the OrCal Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the collateralization of the OrCal Senior Secured Notes.

The Gould Project. The Gould project is also located in Heber, Imperial County, California. The Gould project consists of a bottoming-cycle OEC at Heber 1 and additional Ormat Integrated Two Level Units (ITLU) at Heber 2 and has total generating capacity of 10 MW. The project sells its electrical output under a new long-term power purchase agreement with Southern California Public Power Authority for a fixed price, which in 2006 was $57.50/MWh, which escalates annually at a rate of 1.5%. This power purchase agreement will expire in 2031. The construction of the Gould project was financed with equity, and was included in the financing of OrCal’s Senior Secured Notes issued on December 8, 2005. The OrCal Senior Secured Notes are collateralized by all of the assets of the Heber Complex (and any and all proceeds arising therefrom) and our project subsidiary, OrHeber 2 Inc., the direct owner of the Gould project, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed OrCal’s obligations under the OrCal Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the collateralization of the OrCal Senior Secured Notes. Recently, our project subsidiary that owns the Gould project reached an agreement with Southern California Public Power Authority to eliminate the obligation under the power purchase agreement to share the production tax credits and in exchange to reduce the fixed price under the power purchase agreement by $2/MWh. We have undertaken to OrCal to make up the difference of $2/MWh such that its overall revenues from the project are not affected.

The Steamboat Complex

The Steamboat complex consists of the Steamboat 1/1A project, the Steamboat 2/3 project, the Burdette project and the Steamboat-Hills project.

The Steamboat 1/1A Project. The Steamboat 1/1A project is located in Steamboat Hills, Washoe County, Nevada. The Steamboat 1/1A project includes two power plants which commenced

Table of Contents

commercial operations in 1986 and 1988, respectively. The Steamboat 1/1A project utilizes a binary system and currently has a generating capacity of 2 MW. The Steamboat 1/1A project sells its electrical output to Sierra Pacific Power Company under two separate power purchase agreements. The Steamboat 1/1A project was acquired in June 2003 using internally generated cash, and was refinanced with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The OFC Senior Secured Notes are collateralized by all of the assets of the Steamboat 1/1A project (and any and all proceeds arising therefrom) and our project subsidiary, Steamboat Geothermal LLC, the direct owner of the Steamboat 1/1A project, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed Ormat Funding’s obligations under the OFC Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for further description of collateralization of the OFC Senior Secured Notes.

The initial term of the Steamboat 1 power purchase agreement expired at the end of 2006 but we continue to sell electricity by an automatic extension of the power purchase agreement on a year-by-year basis. We are currently negotiating a renewal of the power purchase agreement for the years 2007 and 2008.

The Steamboat 2/3 Project. The Steamboat 2/3 project is also located in Steamboat Hills, Washoe County, Nevada. The Steamboat 2/3 project consists of two power plants which commenced commercial operations in 1992. The Steamboat 2/3 project utilizes a binary system and has a generating capacity of 24 MW. We have experienced protracted failures of two of the project’s turbines, which were not manufactured by us, and we are in the process of replacing the problematic equipment with turbines of our own design and manufacture. The Steamboat 2/3 project sells its electrical output to Sierra Pacific Power Company under two separate power purchase agreements. The Steamboat 2/3 project was acquired in February 2004 using internally generated cash and proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The OFC Senior Secured Notes are collateralized by all of the assets of the Steamboat 2/3 project (and any and all proceeds arising therefrom) and our project subsidiary, Steamboat Development Corp., the direct owner of the Steamboat 2/3 project, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed Ormat Funding’s obligations under the OFC Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for further description of collateralization of the OFC Senior Secured Notes.

The Burdette Project. The Burdette Project is located in Steamboat, Washoe County, Nevada. The Burdette project has a generating capacity of 21 MW. We completed the construction of this project in November 2005 and we reached commercial operation on February 28, 2006. The project sells and transfers its electrical output and transfers its renewable energy credits to Sierra Pacific Power Company under a power purchase agreement that has a 20-year term ending on December 31, 2026.

The Steamboat-Hills Project . The Steamboat Hills project is also located in Steamboat Hills, Washoe County, Nevada. The Steamboat Hills project is comprised of one plant and commenced commercial operations in 1988. The Steamboat Hills project utilizes a single flash system and water cooled condenser and has a generating capacity of 6 MW, although the capacity under the power purchase agreement is 12.5 MW. The Steamboat Hills project sells its electrical output to Sierra Pacific Power Company pursuant to a power purchase agreement. The project, under the predecessor owner, experienced difficulties operating at full capacity, among other reasons because of a well blow-out. We intend to increase the generating capacity of the Steamboat Hills project by an additional 4 MW in the first half of 2007, to take full advantage of the power purchase agreement. The Steamboat Hills project was acquired in May 2004 using internally generated cash.

The Mammoth Complex

The Mammoth complex is located in Mammoth Lakes, California. The Mammoth complex is comprised of three plants, which commenced commercial operations between 1985 and1990. The Mammoth complex utilizes a binary system and has a generating capacity of 29 MW, including 4 MW

Table of Contents

that we added during the course of 2006. Our project subsidiary, OrMammoth, Inc., owns a 50% partnership interest in Mammoth-Pacific, L.P., which owns 100% of the Mammoth complex. The other 50% partnership interest is owned by an unrelated third party. The Mammoth complex sells its electrical output to Southern California Edison under three separate power purchase agreements. Our 50% ownership interest in the Mammoth complex was acquired in December 2003 using internally generated cash and project finance debt from Beal Bank, and was refinanced with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The OFC Senior Secured Notes are collateralized by a pledge of our 50% ownership interest in Mammoth-Pacific, L.P. and our project subsidiary, OrMammoth Inc., has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed Ormat Funding’s obligations under the OFC Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for further description of collateralization of the OFC Senior Secured Notes.

The Brady Complex

The Brady complex consists of the Brady project and the Desert Peak 2 project.

The Brady Project. The Brady project is located in Churchill County, Nevada and includes the Brady plant and the Desert Peak 1 plant. The Brady plant commenced commercial operations in 1992. The Desert Peak 1 plant, which previously formed part of the Brady complex, commenced commercial operations in 1985, but is currently not operational following its shut down, as described below. The Brady project has a generating capacity of approximately 19 MW, utilizing flash and binary systems, and sells its electrical output to Sierra Pacific Power Company under a long-term power purchase agreement that will expire in 2022. In the second half of 2006, following our conclusion that the continued operation of the Desert Peak 1 plant at the Brady complex was not economical, based on the high costs of repair and maintenance that would be required to keep the Desert Peak 1 plant operational, we shut down the Desert Peak 1 plant. We are replacing the disconnected Desert Peak 1 plant with one of the units of the new Desert Peak 2 project and have been supplying electricity generated by such unit of the Desert Peak 2 project to the Brady project such that the overall output from the Brady project and its performance under its power purchase agreement have not been affected by the Desert Peak 1 plant shut down. We are also in the process of drilling a new production well and redrilling another well, with the intent of restoring the Brady project’s generating capacity to 19 MW during the second half of 2007.

The Brady project was acquired in June 2001 using internally generated cash and was refinanced with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The OFC Senior Secured Notes are collateralized by all of the assets of the Brady project (and any and all proceeds arising therefrom) and our project subsidiary, Brady Power Partners, the direct owner of the Brady project, has jointly and severally with certain of our other subsidiaries, fully and unconditionally guaranteed Ormat Funding’s obligations under the OFC Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the collateralization of the OFC Senior Secured Notes and certain other matters relating to the Brady complex and the OFC Senior Secured Notes.

The Desert Peak 2 Project. The Desert Peak 2 project is located in Churchill County, Nevada (near the Brady project). The Desert Peak 2 project includes a water cooled unit and an air cooled unit, utilizing our OEC units. The aggregate generating capacity of the Desert Peak 2 project is 12 MW. The electrical output from the project will be sold, and renewable energy and environmental credits transferred, to Nevada Power Company under a power purchase agreement that has a 20-year term commencing on the January 1 following the commercial operation date of the project. We expect to declare commercial operation of the Desert Peak 2 project during the first half of 2007. Recently, we have been using a portion of the electrical output from the Desert Peak 2 project to supply the Brady project, as described above. As of February 2007, we no longer supply electricity generated by the Desert Peak 2 project to the Brady project.

The Puna Project

The Puna project is located in the Puna district, Big Island, Hawaii. The Puna plant commenced commercial operations in 1993. The Puna plant utilizes an Ormat geothermal combined cycle system,

Table of Contents

and has a generating capacity of 30 MW. The Ormat geothermal combined cycle system consists of a back pressure steam turbine, in which the lower pressure steam exhausted from the turbine is condensed in a binary system. This system assures a higher efficiency of geothermal steam, with a resulting lower steam rate, in resources producing steam above 150psi (10 bar), or even 100psi if the steam has a high non-condensable gas content. The Puna project sells its electrical output to Hawaii Electric Light Company under two power purchase agreements. Although the Puna project has significant geothermal resources, because of existing geological conditions, these resources are difficult to manage. In the past, the Puna project required extensive levels of investment mainly to address problems with the production and injection wells related to the geothermal resources. The Puna project was acquired in June 2004 with the proceeds of parent company loans and short-term bank loans. We completed operating lease transactions in respect of the project, as described under ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’.

During the second half of 2006, we encountered a mechanical problem in two wells. This caused us to limit the output of the project to approximately 20 MW as a precautionary limit. During the first quarter of 2007, we were able to restore the output to 30 MW, the level of the project’s design capacity.

In addition, we intend to increase the output of the Puna project by an additional 8 MW through the addition of OEC units. We are in the process of negotiating a new power purchase agreement for the additional generating capacity that will be available as a result of such activities.

The OREG 1 Project

The OREG 1 project is a REG project that consists of four power plants constructed on gas compressor stations along a natural gas pipeline in North and South Dakota. The project came on line during the third quarter of 2006 and has a generating capacity of 22 MW. Our project subsidiary has entered into a 25-year power purchase agreement with Basin Electric Power Cooperative (Basin Electric) pursuant to which the project sells the electrical output to Basin Electric.

Foreign Projects

Our projects in operation outside of the United States have a generating capacity of approximately 113 MW. We also have projects under construction in Guatemala and Kenya.

The Leyte Project (The Philippines)

The Leyte project is located in the Philippines, on the Isle of Leyte. The Leyte project consists of four power plants. The Leyte plants utilize steam systems; one conventional flash steam plant and three ORMAT manufactured topping steam turbines and have a combined generating capacity of 49 MW. The ORMAT topping steam turbines generate additional power by using the reduction in pressure to the inlet of the conventional flash steam plant, situated downstream, necessitated when the existing steam field produced steam at a higher pressure than can be accommodated by the conventional flash steam plant. Our project subsidiaries have an 80% partnership interest in Ormat-Leyte Co. Ltd., which owns 100% of the Leyte project. The remaining 20% partnership interest in Ormat-Leyte Co. Ltd. is held by two unrelated third parties. In August 1995, following a build-operate-transfer agreement, which we refer to as BOT, international tender, Ormat Inc. (which later transferred its interest in the BOT agreement to Ormat-Leyte Co. Ltd.) entered into a BOT agreement with PNOC-Energy Development Corporation, a Philippine company wholly owned by Philippine National Oil Company, a government-owned company. Under the BOT agreement, the project will be transferred to PNOC-Energy Development Corporation in September 2007 for no consideration. We do not anticipate any material financial loss as a result of such transfer, although going forward this will reduce our foreign generation capacity by 49 MW. Ormat-Leyte Co. Ltd. has an outstanding non-recourse loan from the Export-Import Bank of the United States, the outstanding balance of which was $3.8 million as of December 31, 2006. The loan is due and payable in approximately equal quarterly installments through July 2007.

The Government of The Philippines has initiated the privatization of its electricity industry. However, we cannot foresee when such privatization may be completed. If such privatization is

Table of Contents

achieved in a manner that jeopardizes PNOC-Energy Development Corporation’s or its affiliate’s ability to comply with their obligations under the BOT agreement, the parties are required to negotiate an amendment to the power purchase agreement. Should they fail to reach an agreement, PNOC-Energy Development Corporation has the obligation (and our project subsidiary has the right to require PNOC-Energy Development Corporation) to buy out Ormat-Leyte Co. Ltd.’s rights in the project at a price based upon the net present value of the projected cash flow from the project for the remaining term of the BOT agreement.

The Momotombo Project (Nicaragua)

The Momotombo project is located in Momotombo, Nicaragua. The Momotombo project is comprised of one plant and a geothermal field. The plant was already in existence when we signed the concession agreement for the project in March 1999, and had commenced commercial operations in the mid-1980s utilizing a dual flash system. During 2006 we increased the output of the Momotombo project by 3 MW through a work-over of the project’s existing wells, bringing the generating capacity to approximately 30 MW. The Momotombo project has a power purchase agreement with Empresa Distribuidora de Electricidad del Norte (DISNORTE) and Empresa Distribuidora de Electricidad del Sur (DISSUR), two corporations which own the power distribution rights in Nicaragua. Our project subsidiary, which operates the Momotombo project, has an outstanding loan from Bank Hapoalim B.M., the outstanding balance of which was $11.3 million as of December 31, 2006.

The Olkaria III Project — Phase I (Kenya)

The Olkaria III project is located in Naivasha, Kenya. The Olkaria III project is comprised of one plant, which commenced commercial operation in August 2000, and a geothermal field. The plant currently has a generating capacity of approximately 13 MW (Phase I). We are working on the construction of Phase II of this project which we expect, upon completion, will increase the generating capacity of the Olkaria III project to approximately 48 MW. A description of Phase II of this project is set forth below in ‘‘Projects under Development.’’ Phase I of the Olkaria III project utilizes a binary system. In November 1998, following an international tender, our project subsidiary entered into a power purchase agreement with the Kenya Power and Lighting Co. Ltd. (KPLC), the Kenyan parastatal electricity transmission and distribution company, which was recently amended and restated in January 2007 . Our project subsidiary leases the site on which the geothermal resources and the plant facilities are located from the Kenyan government, pursuant to an agreement which will expire in 2040. The Kenyan government granted our project subsidiary a license giving it 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 by us. The Kenyan Minister of Energy has the right to terminate or revoke the license in the event our project subsidiary ceases work in or under the license area during a period of six months, or has failed to comply with the terms of the license or the provisions of the law relating to geothermal resources. Our project subsidiary is obligated to pay the Kenyan government monthly fees and royalties based on the amount of power supplied to KPLC.

The Zunil Project (Guatemala)

The Zunil project is located in Zunil, Guatemala. The Zunil project is comprised of one plant which commenced commercial operations in 1999. The plant utilizes a binary system consisting of Ormat Energy Converters and has a generating capacity of 24 MW. The project is owned by Orzunil I de Electricidad, Limitada, which owns 100% of the Zunil project. Another of our subsidiaries provides operation and maintenance services to the project. The Zunil project sells its generating capacity to Instituto Nacional de Electrification pursuant to a power supply agreement. As of the date of this annual report, Orzunil I de Electricidad, Limitada has two senior outstanding non-recourse loans, one from International Finance Corporation (IFC) and the other from the Commonwealth Development Corporation (CDC), the aggregate total balance of which was, as of December 31, 2006, $19.4 million. The loans are due and payable in quarterly installments through November 2011. Each of the IFC and the CDC owned 14.1% of the issued and outstanding partnership interests of Orzunil I de

Table of Contents

Electricidad, Limitada. On March 13, 2006 and on August 16, 2006, we consummated the acquisition of an additional 50.8% and 28.2%, respectively, of the ownership interest in the Zunil project and thereby increased our 21% ownership interest to 100% (97% on a fully diluted basis assuming the exercise of an option by a third party).

Projects under Construction

We are in varying stages of construction or enhancement of projects, both domestic and foreign. Based on our current construction schedule, we expect to add new generating capacity of approximately 114 MW in the United States and approximately 55 MW throughout the rest of the world by the end of 2008 or early 2009. This amount will be reduced by the 49 MW (of which we own 80%) of the Leyte project. The following is a description of the projects currently undergoing construction:

The Amatitlan Project (Guatemala)

Our project subsidiary has completed the construction of a geothermal power plant in Amatitlan, Guatemala on a ‘‘build, own and operate’’ or ‘‘BOO’’ basis. The project is currently in final completion tests. The project is comprised of one power plant, which will have a generating capacity of 20 MW, and has obtained the rights to various geothermal production and reinjection wells. The Amatitlan plant uses our Ormat Energy Converters.

The term of the power purchase agreement for the Amatitlan project is 20 years from the date of the commencement of operations at the power plant or 23 years from the date of commencement of the construction work, whichever is later. During a period of two years after the completion of the construction of the power plant, and subject to the signing of an additional agreement with the Instituto Nacional de Electrification and the result of a feasibility test, our project subsidiary may increase the power generating capacity of the power plant through the drilling of additional wells and adding another power plant by up to an aggregate of 50 MW. We anticipate that commercial operation of the Amatitlan project will be declared in the first half of 2007.

The local municipal authorities have claimed that a construction license is required for the project, while our local counsel has advised us that no such license is required under the applicable laws and regulations. We are challenging the claim of the local municipal authorities.

The Galena 2 Project (U.S.)

The construction of the Galena 2 project in Washoe County, Nevada is completed and we are in the start up phase. The project is expected to have a generating capacity of 10 MW. Our project subsidiary will sell electrical output from the plant, and transfer the renewable energy and environmental credits, to Nevada Power Company under a power purchase agreement with a 20-year term that will commence on the first day of the year following the commercial operation date of the plant. The power purchase agreement was signed as part of Nevada Power Company’s efforts to comply with Nevada’s renewable portfolio standards.

The Heber South Project (U.S.)

We have started the construction of a 10 MW power plant, which will be located in what is known as the Heber Known Geothermal Resource Area or Heber KGRA. The construction activity is expected to include the drilling of production and injection wells and the construction of an OEC unit. Completion is expected in the first half of 2008. The power purchase agreement for this addition to the Heber complex is still under negotiation.

The Galena 3 Project (U.S.)

We have started the construction of the Galena 3 project, which will be located in Washoe County, Nevada. The project will increase the output of the Steamboat Complex by 17 MW of power

Table of Contents

generation under a 20-year power purchase agreement with Sierra Pacific Power Company. We expect the construction, which will bring the total generating capacity of the Steamboat Complex to approximately 85 MW, to be completed by the end of 2007 or the beginning of 2008.

The Brawley Phase I Project (U.S.)

We have started the construction of a 50 MW power plant, which will be located in the North Brawley known geothermal resource area in Imperial County, California. Drilling started in February 2007 and we are negotiating the power purchase agreement for this project.

The OrSumas Project

The OrSumas project is a REG plant currently in the construction stage and is expected to have a generating capacity of 5 MW. Our project subsidiary has entered into a 20-year power purchase agreement with Puget Sound Energy pursuant to which the project will sell its electrical output to Puget Sound Energy. The power plant will be constructed on a gas compressor station along the Northwest Pipeline in the State of Washington. Our engineering work has identified certain environmental issues on the proposed project site. We are currently in the midst of discussions with the pipeline company regarding these environmental issues for which we are not responsible. The outcome of these discussions may result in a delay or termination of the project activities.

The Olkaria III Project — Phase II (Kenya)

As previously noted, our project subsidiary in Kenya has been working towards the construction of Phase II of the Olkaria III project. As of the date of this report, our project subsidiary has drilled wells and commenced preliminary construction activities but has not begun any material construction activities with respect to Phase II. On January 19, 2007, we entered into an Amended and Restated Power Purchase Agreement and a Project Security Agreement with Kenya Power and Lighting Co. (KPLC), the Kenyan parastatal electricity transmission and distribution company, with respect to Phase II of the Olkaria III project. These agreements were executed after the receipt of appropriate regulatory approvals from the Kenyan authorities. The construction of the second phase of the project is expected, upon completion, to add approximately 35MW to the existing facility, bringing the project’s total capacity to approximately 48MW. Following completion of Phase II, total anticipated annual revenues from the project will be approximately $32 million.

Under the Amended and Restated Power Purchase Agreement, the parties agreed to (i) shorten the construction period for Phase II to approximately twenty one months commencing from the deposit of the agreed collateral by KPLC, which occurred on February 7, 2007; (ii) change the technical configuration of Phase II such that the plant will use OEC units to generate electricity; and (iii) reduce the tariff payable by KPLC on the total capacity of the plant upon completion of Phase II.

Under the Project Security Agreement, KPLC provided a letter of credit in an amount equal to the value of four months of anticipated revenues from the project under the Amended and Restated Power Purchase Agreement (currently valued at approximately $8 million).

Other Projects

We are currently pursuing construction or enhancement activities in the following projects:


	•	Steamboat Hills project: We plan to complete the construction of an additional 4 MW during the first quarter of 2007; and


	•	Ormesa project: We plan to complete the construction of an additional 10 MW during the first quarter of 2007; and


	•	Puna project: We plan to add 8 MW through the construction of OEC units by the end of 2008 or early 2009. We are in discussions with Hawaii Electric Light Company for the sale of additional electrical power from the Puna project.

Table of Contents

Projects under Development and Future Projects

We also have projects under development in the United States, China 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 Carson Lake Project (U.S.)

We are currently developing the Carson Lake project, which will be located in Churchill County, Nevada. The project will deliver between 18 MW to 30 MW of power generation under a 20-year power purchase agreement with Nevada Power Company. We expect the construction to be completed during 2009. The leases for this project have been obtained through an agreement with the U.S. Department of the Navy, which will get 5% of the revenues as royalties during the first 20 years of operation.

The Buffalo Valley Project (U.S.)

We are currently developing the Buffalo Valley project, which will be on BLM leases located in Lander County, Nevada. The project will deliver between 18 MW to 30 MW of power generation under a 20-year power purchase agreement with Nevada Power Company. We expect the construction to be completed during 2009.

The OREG II Projects (U.S.)

We recently entered into a Power Purchase Option Agreement with Basin Electric Power Cooperative (Basin Electric) regarding five new REG Power Plants, with a total generating capacity of 27.5 MW, along the Northern Border Pipeline in the States of Montana, North Dakota and Minnesota. According to the Option Agreement, Basin Electric will work towards fulfilling certain conditions with the goal of confirming its readiness to enter into a definitive 25-year power purchase agreement. We have already secured the rights to the waste heat for two of the new power plants and will continue to work towards obtaining the rights to the remaining three new power plants. The approval for construction of the new power plants is expected during 2007.

The Brawley Phase II Project (U.S.)

If the results of the drilling activities we are currently undertaking in connection with the Brawley Phase I project will indicate the existence of sufficient geothermal resource, we plan to construct an additional 50 MW power plant, which will be located in the North Brawley known geothermal resource area in Imperial County, California, adjacent to Phase I of the Brawley project.

The Yunnan Project (China)

OrYunnan Geothermal Co., Ltd., which is a joint venture established between our project subsidiary and Yunnan Province Geothermal Development Co., Ltd., owns exclusive rights to develop all of the geothermal resources in Teng Chong County, Baoshan City, in Yunnan Province, southwest China. Our project subsidiary owns 85% of the interests in OrYunnan Geothermal Co. Ltd., which owns all of the ownership interests in the Yunnan project. The area of the geothermal concession is approximately 65 square miles and is located approximately 200 miles southwest of Kunming, the provincial capital of Yunnan, and approximately 40 miles from the border with Myanmar. We estimate the potential of the geothermal resources in the concession area to be between 150 to 200 MW. Initially, our project subsidiary and its partner intend to develop a geothermal field and construct a power plant with a generating capacity of approximately 42 MW, which we estimated would require a capital investment of approximately CNY 776.9 million (approximately $99.6 million calculated at the prevailing exchange rate on December 31, 2006). Our project subsidiary is awaiting Yunnan Provincial Government approval, following which negotiations with the provincial utility company towards the signing of a power purchase agreement may conclude. Following the approval of the Yunnan Provincial Government, the electricity feed-in tariffs would still require central government approval.

Table of Contents

Such tariffs will be based on the implementing regulations to be announced shortly. On May 29, 2002, our project subsidiary entered into a memorandum of understanding, which we refer to as an MOU, regarding the main terms of the power purchase agreement and other major project agreements with Yunnan Electric Power Co., Ltd., a state-owned utility company, concerning the purchase of electric power by the utility company from our project subsidiary on a 30-year basis and the related interconnection arrangements. The MOU estimated that the commercial operation date of the plant was to be January 1, 2006. However, we have been in the development stage of the OrYunnan Project for several years and this date will have to be extended for an appropriate period following the completion of the Chinese central government’s approval.

The 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 300 MW that is expected to come on line in phases between 2010 and 2012. We estimate that our minority interest equivalent will range between 45 MW to 60 MW.

Exploration Activity

In addition to the geothermal projects under construction and development, we have various leases for geothermal resources, in which we have started exploration activity. These geothermal resources include the following:


	•	Grass Valley — Lander County, NV;


	•	Jersey Valley — Pershing County, NV;


	•	Magic Hot Springs — Blaine & Camas Counties, Idaho;


	•	Fireball Ridge — Churchill County, NV;


	•	Gabbs Valley — Nye County, NV;


	•	Rock Hills — Esmeralda County, NV.

Our exploration activity is intended to provide us with an indication and better understanding of the availability of geothermal resources in the areas covered by these leases and will enable us to make a decision regarding their development. We do not expect that our exploration activity will lead to commercial projects in each case.

Development Inventory

In addition to the geothermal projects under construction, development or exploration, we have various geothermal leases for future development in the United States and other development rights outside of the United States. These geothermal leases and rights include the following:


	•	Oregon — one site;


	•	California — three sites;


	•	Nevada — three sites;


	•	Hawaii — one site;


	•	Idaho — three sites;


	•	Texas — several leases; and


	•	Outside of the United States — two sites.

Table of Contents

Operations of our Products Segment

Power Units for Geothermal Power Plants. We design, manufacture and sell power units for geothermal electricity generation, which we refer to as Ormat Energy Converters or 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 covered by letters of credit. Ormat has not received any claims under the performance guarantees to date.

Power Units for Recovered Energy-Based Power Generation. We design, manufacture and sell power units used to generate electricity from recovered energy or so-called ‘‘waste heat’’ that is generated as a residual by-product of gas turbine-driven compressor stations and a variety of industrial processes, such as cement manufacturing, and is not otherwise used for any purpose. Our existing and target customers include interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators, and other companies engaged in other energy-intensive industrial processes. We view recovered energy generation as a significant market opportunity for us, and plan to utilize two different business models in connection with such business opportunity. The first, 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 into long-term power purchase agreements with off-takers to sell the electricity generated by the recovered energy generation unit that utilizes such industrial waste heat. We expect that the power purchasers in such cases will be investor-owned electric utilities or local electrical cooperatives. In early 2006, we signed a supply contract with UltraTech Cement Ltd. in Mumbai, India for the supply of one OEC for a new REG power plant.

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). Recently we signed two agreements (with ICQ and Ultratech) for the supply of Ormat OEC systems for Recovered Energy Generation plants.

Our recovered energy generation units, if structured properly, may be eligible for favorable tax treatment, such as the seven year modified accelerated cost recovery under relevant U.S. federal tax rules.

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. Our remote power units were recently supplied to the Sakhalin pipeline in Russia. The terms of sale of the turbo-generators are similar to those for the power units produced for power plants.

Engineering, Procurement and Construction (EPC) of Power Plants. We engineer, procure and construct, as an EPC contractor, geothermal and recovered energy power plants on a turnkey basis,

Table of Contents

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

We also design and construct the recovered energy generation 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. For example, recently we entered into supply and construction contracts with Alliance pipeline in Western Canada for an Ormat Recovered Energy Generation power plant.

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, ASME and TÜV, and we are an approved supplier to many electric utilities around the world.

Backlog

The Company and its wholly owned subsidiaries have a products backlog of $89.5 million as of February 28, 2007, which includes revenues for the period between January 1, 2007 and February 28, 2007, compared to $81.8 million as of March 15, 2006. The following is a breakdown of the Products Segment backlog:

Table of Contents


Products backlog
	Expected Completion of Contract		Sales Expected to be Recognized in 2007 (in millions)			Sales Expected to be Recognized in the Years Following 2007 (in millions)
North America
Raft River		2007		$	16.2		$	—
Blundell		2007			5.0			—
NRGreen, Canada		2007			24.8			—
Enpower Green, Canada		2008			2.4 − 4.9			4.1 − 6.6
Total North America					48.4 − 50.9			4.1 − 6.6
Worldwide (Except North America)
ICQ, Italy		2007			0.5			—
Enagas Almendralejo, Spain		2007			3.1			—
Comita, Russia		2008			—			2.4
Mokai 1A, New Zealand		2007			0.4			—
Landau Geo X GmbH, Germany		2007			3.6			—
Sakhalin, Russia		2007			2.4			—
Bongkot, Thailand		2007			0.4			—
Ngawha II, New Zealand		2008			5.8 − 10.3			10.5 − 15.0
Other Units		2007			0.9			—
Total Worldwide (Except North America)					17.1 − 21.6			12.9 − 17.4
Total Products Backlog				$	65.5 − 72.5		$	17.0 − 24.0

We expect that our revenues from electricity for the 2007 fiscal year will be approximately $220 million from our wholly owned projects and approximately $18.0 million from our subsidiaries accounted for by the equity method.

Our Technology

Our proprietary technology covers power plants operating according to the Organic Rankine Cycle only or in combination with the Steam Rankine Cycle and Brayton Cycle, as well as integration of power plants with 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, or CAD, 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) area, we are examining two-level recovered energy systems and new motive fluids.

We also construct 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.

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 disposition 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

Table of Contents

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. Accidental or fugitive emissions (that result from minor leaks) of motive fluids are within the limits defined by federal, state and local regulatory standards.

Other advantages of our technology include simplicity of operation and easy maintenance, low RPM, temperature and pressure in the Ormat Energy Converter, 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 could 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 Ormat Energy Converter’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 Ormat Energy Converter 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 a conventional steam turbine can exhibit, requires no water treatment as it is air cooled, and does not require the continuous presence of a steam licensed operator on site.

More than 70 United States patents (and about 10 pending patents) cover our products (mainly power units based on the Organic Rankine Cycle) and systems (mainly geothermal power plants and industrial waste heat recovery for electricity production). The systems-related patents cover not only a particular component but rather the overall effectiveness of the plant’s systems from the ‘‘fuel’’ (i.e., geothermal fluid, waste heat, biomass or solar) to generated electricity. The duration of such patents ranges from one year to 14 years. No single patent on its own is material to our business.

The products-related patents cover components such as turbines, heat exchanges, seals and controls. The system patents cover subjects such as disposal of non-condensable gases present in geothermal fluids, power plants for very high pressure geothermal resources and use of two-phase fluids. 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.

We are also involved in developing new technology to extract heat from the earth by circulating fluid through an enhanced or man-made reservoir created in naturally low permeable or water-poor rocks. We are undertaking this development in cooperation with GeothermEx Inc., the University of Utah, Energy & Geoscience Institute, the University of Nevada-Reno and the Great Basin Center for Geothermal Energy, with funding support from the United States Department of Energy.

Competition

The power generation industry is characterized by intense competition from electric utilities, other power producers, and marketers. In recent years, the United States in particular has seen increasing competition in power sales, in part due to excess capacity in a number of U.S. markets and an emphasis on short-term markets. In the last year, competition from the wind and solar power generation industry has increased. While the current demand for renewable energy is large enough that this increased competition has not impacted our ability to obtain new power purchase agreements, this increased competition may contribute to a reduction in electricity prices for new renewable projects.

In the geothermal power generation sector, our main competitors in the United States are CalEnergy, Calpine (which filed for protection under Chapter 11 of the U.S. Bankruptcy Code in late 2005), Caithness and other smaller-sized developers such as U.S. Geothermal. Some of these companies are also active outside of the United States. Outside of the United States, aside from these companies and ENEL, which is based in Italy, we may face competition from national electric utilities or state-owned oil companies.

Table of Contents

In the products business, our main competitors are Mitsubishi, Fuji and Toshiba of Japan, GE/Nuevo Pignone, Ansaldo and Turboden of Italy, Siemens of Germany, Alstom of France and Kaluga of Russia. Recently, two new small players have been trying to penetrate the market. In the remote power unit business, we face competition from Global Thermoelectric, as well as from manufacturers of diesel generator sets. Recently, United Technologies announced the introduction of a small 200 kW Organic Rankine Cycle unit.

Siemens of Germany as well as other manufacturers of conventional steam turbines are potential competitors in the recovered energy generation business; although we believe that our recovered energy generation system has technological and economical advantages over the Siemens/Kalina technology and, under certain conditions, conventional steam technology.

We also compete with companies engaged in the power generation business from renewable energy sources other than geothermal energy, such as wind power, solar power and hydro-electric power.

None of our competitors competes with us both in the sale of electricity and in the products business.

Customers

Most of our revenues from the sale of electricity in the year ended December 31, 2006 were derived from fully-contracted energy and/or capacity payments under long-term power purchase agreements with governmental and private utility companies. Southern California Edison, Hawaii Electric Light Company and Sierra Pacific Power Company accounted for 30.0%, 15.1% and 12.8% of revenues, respectively, for the year ended December 31, 2006. Based on publicly available information, as of December 31, 2006, the issuer ratings of Southern California Edison, Sierra Pacific Power Company and Nevada Power Company (a power purchaser for the Desert Peak 2 and Galena 2 projects) were A3 (stable outlook), Ba3 (stable outlook) and Ba3 (stable outlook), respectively, from Moody’s Investors Services and BBB+ (stable outlook), BB− (stable outlook), and BB− (stable outlook), respectively, from Standard & Poor’s Ratings Services and the issuer rating of Hawaii Electric Light Company was BBB+ (negative outlook) from Standard & Poor’s Ratings Services. SCPPA, which has purchased the power from the Gould project since the beginning of 2006, has senior unsecured debt ratings ranging from A1 from Moody’s and A+ from S&P, in each case with a stable ratings outlook. The credit ratings of any power purchaser may decrease from time to time. There is no publicly available information with respect to the credit rating or stability of the power purchasers under the power purchase agreements for our foreign power projects.

Our revenues from the products business were derived from contractors or owners or operators of power plants, process companies and pipelines.

Raw Materials, Suppliers and Subcontractors

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

Since 2005 we have increased the volume of work ordered from subcontractors for some of the manufacturing for our products components and for construction activities of our power plants, which allowed us to expand our construction and development capacity on an as-needed basis. We are not dependent on any one subcontractor and expect to be able to replace any subcontractor, or assume such manufacturing and construction activities of our projects ourselves without adverse effect to our operations.

Employees

As of December 31, 2006, we employed 774 employees, of which 252 were located in the United States, 363 were located in Israel and 159 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.

Table of Contents

None of our employees (other than the Momotombo project employees) are represented by a labor union, and we have never experienced any labor dispute, strike or work stoppage. We consider our relations with our employees to be satisfactory. We believe our future success will depend on our continuing ability to hire, integrate and retain qualified personnel.

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

Insurance

We maintain business interruption insurance, casualty insurance, including flood and earthquake coverage, and primary and excess liability insurance, as well as customary worker’s compensation and automobile insurance and such other insurance, if any, as is generally carried by companies engaged in similar businesses and owning similar properties in the same general areas and financed in a similar manner. To the extent any such casualty insurance covers both us and/or our projects, on the one hand, and any other person and/or plants, on the other hand, we generally have specifically designated as applicable solely to us and our projects ‘‘all risk’’ property insurance coverage in an amount based upon the estimated full replacement value of our projects (provided that earthquake and flood coverage may be subject to annual aggregate limits depending on the type and location of the project) and business interruption insurance in an amount that also varies from project to project.

We generally purchase insurance policies to cover our exposure to certain political risks involved in operating in developing countries. Political risk insurance policies are generally issued by entities which specialize in such policies, such as the Multilateral Investment Guarantee Agency (a member of the World Bank Group), and from private sector providers, such as Zurich Re, AIG and other such companies. To date all of our political risk insurance contracts are with the Multilateral Investment Guarantee Agency and with Zurich Re. Such insurance policies cover, in general, and 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 projects in operation except for the Leyte project.

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 project is a ‘‘Qualifying Facility’’. There are two types of Qualifying Facilities: cogeneration facilities and small power production facilities. 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 (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 megawatt 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, or waste resources; and (ii) an application for

Table of Contents

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 exempted Qualifying Facilities from regulation under the Public Utility Holding Company Act of 1935 (PUHCA) and exempts Qualifying Facilities from most provisions of the Federal Power Act (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 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’’).

Pursuant to the Energy Policy Act of 2005, FERC has recently issued a final rule that will require Qualifying Facilities to obtain market-based rate authority pursuant to the FPA for sales of energy or capacity (i) from facilities larger than 20 MW in size; (ii) 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 (iii) 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.

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 has recently issued a rule to implement these provisions of the Energy Policy Act of 2005. This rule gives nine (9) utilities the right to apply to eliminate the mandatory purchase obligation if the utility is a member of one of four regional transmission organizations. None of our domestic projects sells power pursuant to contracts with utilities in any of these four regional transmission organizations. 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, which is currently under review by FERC to ensure that its provisions prevent undue discrimination in the provision of transmission service. Further, the rule provides a procedure for utilities that are not members of the four named regional transmission organizations to file to obtain relief from the mandatory purchase obligation on a service territory-wide basis, and establishes procedures for affected Qualifying Facilities to seek reinstatement of the purchase obligation. The rule protects a Qualifying Facility’s rights under any contract or obligation involving purchases or sales that are entered into after August 8, 2005 but before FERC has determined that the contracting utility is entitled to relief from the mandatory purchase obligation. The rule also 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.

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 projects will continue to meet all of the criteria required for Qualifying Facilities under PURPA. However, since the Heber Projects have power purchase agreements 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 Projects loses its Qualifying

Table of Contents

Facility status our operations could be adversely affected. Loss of Qualifying Facility status would eliminate the Heber Project’s exemption from the FPA and thus, among other things, the rates charged by the Heber Projects in the power purchase agreements with Southern California Edison and SCPPA would become subject to FERC regulation. Further, it is possible that the utilities that purchase power from the projects could successfully obtain an elimination of the mandatory-purchase obligation in their service territories. If this occurs, the Project’s existing power purchase agreements will not be affected, but the utilities will not be obligated under PURPA to renew these power purchase agreements or execute new power purchase agreements upon the existing power purchase agreements’ expiration.

PUHCA

PUHCA has been repealed, effective February 8, 2006, pursuant to the Energy Policy Act of 2005. Although PUHCA was repealed, the Energy Policy Act of 2005 created a new Public Utility Holding Company Act of 2005 (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. 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. By virtue of being Qualifying Facilities that make only wholesale sales of electricity, Qualifying Facilities already 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 state regulation.

FPA

Pursuant to the FPA, the FERC has exclusive rate-making jurisdiction over 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 generally exempt from the FPA. If any of the projects were to lose its Qualifying Facility status, such project could also 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 projects could require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility. Even if a project does not lose Qualifying Facility status, pursuant to a final rule issued by FERC pursuant to the Energy Policy Act of 2005, if a power purchase agreement with a project is terminated or otherwise expires, the project will become subject to rate regulation under the Federal Power Act.

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

Moreover, the loss of the Qualifying Facility status of any of our projects selling energy to Southern California Edison could also permit Southern California Edison, pursuant to the terms of its power purchase agreement, to cease taking and paying for electricity from the relevant project and to seek refunds for past amounts paid. In addition, the loss of any such status would result in the occurrence of an event of default under the indenture for the bonds and hence would give rise to the ability of the indenture trustee to exercise remedies pursuant to the indenture and the other financing documents.

Table of Contents

State Regulation

Our projects 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 projects each sell or will sell their electrical output under power purchase agreements to electric utilities (Sierra Pacific Power Company, Nevada Power Company, Southern California Edison or Southern California Public Power Authority). All of the utilities except Southern California Public Power Authority are regulated by their respective state public utility commissions. Sierra Pacific Power Company and Nevada Power Company are regulated by the Public Utility Commission of Nevada. Southern California Edison and a small portion of Sierra Pacific Power Company in the Lake Tahoe area are regulated by the California Public Utility Commission.

Under Hawaii law, non-fossil generators are not subject to regulation as public utilities. Hawaii law provides that a geothermal power producer is to negotiate the rate for its output with the public utility purchaser. If such rate cannot be determined by mutual accord, the Hawaii Public Utility 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 cost it would otherwise incur if it produced the energy and capacity itself or purchased it from another source. Our project in Hawaii has a long term power purchase agreement with Hawaii Electric Light Company.

Foreign Regulation of the Electric Utility Industry

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 project 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 new energy sector in the country. Law No. 272-98 provides for the establishment of a National Energy Commission, which we refer to as CNE, which is responsible for setting policies, strategies and objectives for such sector and approving indicative plans therefor. Law No. 271-98 formally assigned regulatory, supervisory, inspection and oversight functions to the Nicaraguan Institute of Energy, which we refer to as INE.

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

In 2007, Nicaragua passed a law 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 responsabilities of the National Energy Commission (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 has retained title and control of the transmission assets and has created the Empresa Estatal de Transmision (ENTRESA), which is in charge of the operation of the transmission system in the country and of the new wholesale market. As part of the recent restructuring of the energy sector, most of the distribution facilities previously owned by the Nicaraguan Electricity Company, the government-owned vertically-integrated monopoly, were transferred to two companies, Empresa Distribuidora de Electricidad del Norte (DISNORTE) and Empresa Distribuidora de Electricidad del Sur (DISSUR), which in turn were privatized and acquired by an affiliate of Union Fenosa, a large Spanish utility. Following such privatization, the power purchase agreement for our Momotombo project was assigned by the Nicaraguan Electricity Company to DISNORTE and DISSUR. A subsidiary of the Nicaraguan Electricity Company, ENTRESA, owns the transmission grid. In addition, a National Dispatch Center was created to work with ENTRESA and provide for dispatch and wholesale market administration.

Table of Contents

Guatemala . The General Electricity Law of 1996 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 National Electric Energy Commission (CNEE) and a new wholesale power market administrator, the Administrator of the Wholesale Market, for the regulation and administration of such sector. The CNEE functions as an independent agency under the Ministry of Energy and Mines and is in charge of regulating the electricity law, overseeing the market and setting rates for transmission services and for electricity service 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 Projects in order to promote the development of renewable energy projects in Guatemala. Such law provides certain benefits to companies utilizing renewable energy, including a 10-year corporate income tax; VAT and customs duty exemption and a 10-year business tax exemption.

Kenya. Kenya’s Electric Power Act of 1997 restructured the electricity sector in such country. Among other things, the Act provides for the licensing of electricity power producers and public electricity suppliers or distributors. Kenya Power and Lighting Co. Ltd. (KPLC) is the only licensed public electricity supplier and has a monopoly in the transmission and distribution of electricity in the country. The Act permitted Independent Power Producers (IPPs) to install power generators and sell electricity to KPLC, which is owned by various private, and government entities and which currently purchases energy and capacity from two other IPPs in addition to our Olkaria III project. The 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.

Philippines. The Philippine’s Electric Power Industry Reform Act of 2001 created the Energy Regulatory Commission, which is an independent quasi-judicial regulatory body mandated to promote competition, encourage market development, ensure customer choice and penalize abuse of market power in the restructured electricity industry. The Energy Regulatory Commission is responsible for the enforcement of the rules and regulations governing the operations of the electricity spot market once it is established and the activities of the spot market operator and other participants to ensure a greater supply and rational pricing of electricity. In addition, the Energy Regulatory Commission determines, fixes, and approves transmission and distribution wheeling charges and retail electricity rates for the captive market of a distribution utility through a methodology that it establishes and enforces. The Energy Regulatory Commission also monitors and takes measures to penalize abuse of market power and anti-competitive or discriminatory behavior by any electric power industry participant.

Permit Status

While our power generation operations produce electricity without emissions of certain pollutants such as nitrogen oxide, and with far lower emissions of other pollutants such as carbon dioxide, some of our projects do emit air pollutants in quantities that are subject to regulation under applicable environmental air pollution laws. Such operations typically require air permits. Especially critical to our geothermal operations are those permits and standards applicable to the construction and operation of geothermal wells and brine reinjection wells. In the United States, injection wells are regulated under the federal Safe Drinking Water Act Underground Injection Control, which we refer to as UIC, program. Our injection wells typically fall into UIC Class V, one of the least regulated categories, because fluids are reinjected to enhance utilization of the geothermal resource. Our projects 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 their operation. Some of the environmental permits and governmental approvals that have been issued to the projects contain conditions and restrictions, including restrictions or limits on emissions and discharges of pollutants and contaminants, or may have limited terms.

Table of Contents

Our operations are designed and conducted to comply with applicable permit requirements. Non-compliance with any such requirements could result in fines or other penalties. We are not aware of any non-compliance with such requirements that would be likely to result in material fines or penalties; however, the Heber 1 and 2 projects received a notice from the California Division of Oil, Gas and Geothermal Resources that the pressure levels at some of the geothermal fluid injection wells were too high, and the California Regional Water Quality Control Board has notified the Heber 1 and 2 projects that recent tests have resulted in lower-than-required survival rates for bioassay toxicity tests conducted on the cooling tower blowdown water discharged under the NPDES (National Pollutant Discharge Elimination System) permit. In order to address the pressure levels at the Heber 1 and 2 projects, the Heber 1 and 2 projects proposed the construction and operation of a pipeline to carry geothermal injection fluid to other project injection wells, which proposal has been accepted as an appropriate solution to the pressure level by the California Division of Oil, Gas and Geothermal Resources. The pipeline was completed in the first quarter of 2005. With the cooperation of the California Regional Water Quality Control Board, Colorado River Basin Region, the Heber 1 and 2 projects are also conducting more frequent monitoring and bioassays, and conducting a Toxicity Identification Evaluation (TIE) study in an effort to determine the source of the apparent cooling tower blowdown water toxicity. If the source of the toxicity is not identified, or cannot easily be corrected, the Heber 1 and 2 projects may instead seek authority to inject the cooling tower blowdown water into the geothermal injection reservoir, as do other geothermal projects in the Imperial Valley.

Our Steamboat Hills Project was recently advised by the Washoe County Water Department that certain changes had been observed in the course of the County’s monitoring of well chemistry and was asked to explain why this was occurring. In the course of our investigation, we discovered that a liner in a geothermal fluid injection well failed, resulting in injection of the spent geothermal fluid at a higher depth than the designed and permitted depth for such injection. The County Water Department and the State have also indicated their concern that the injection well may be situated near a geological fault, which may also be causing the movement of injected fluid into a higher zone of the groundwater aquifer. We engaged an outside geothermal consultant to examine the situation and have since completed the well repair work. We do not believe that the injection well has had a material impact on the aquifer or that it is improperly placed. We have agreed with the State to conduct an expanded monitoring program and to continue to study the issue. If it should be determined that the injection well location is not acceptable, it may be necessary to drill a new injection well to manage the spent geothermal fluids.

As of the date of this annual report, all of the material permits and approvals currently required to operate our projects have been obtained and are currently valid, except for the fact that certain permits for some of the projects are held in the name of predecessor owners and except for those permits which must be transferred or reissued to the correct entity. We believe this will occur in the ordinary course and we have already filed some of these applications. In addition, we are required to obtain permits for both the construction and operational phases of our projects under construction or enhancement. As of the date of this annual report, we have obtained and are in compliance with most of the material permits and approvals currently required for our projects that are under construction or enhancement. There are some permits that need to be obtained in the future. We believe we will be able to obtain those permits and approvals without material delay and without incurring additional material costs.

Environmental Laws and Regulations

Geothermal operations can produce significant quantities of brine and scale, which builds up on metal surfaces in our equipment with which the brine comes into contact. These waste materials, most of which are currently reinjected into the subsurface, can contain various concentrations of hazardous materials, including arsenic, lead, and naturally occurring radioactive materials. We also use various substances, including isobutene, isopentane, and industrial lubricants, that could become potential contaminants and are generally flammable. Hazardous materials are also used and generated in connection with our equipment manufacturing operations in Israel. As a result, our projects are

Table of Contents

subject to numerous domestic and foreign federal, state and local statutory and regulatory standards relating to the use, storage, fugitive emissions and disposal of hazardous substances. The cost of any remediation activities in connection with a spill or other release of such contaminants 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 projects, that has materially impaired any of the project sites, any disposal or release of these materials onto project sites, other than by means of permitted injection wells, could 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 project site (which we lease), but because of significant surface disturbance and construction since that time further physical evaluation 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 the former facilities and any associated underground storage tanks would have already been encountered if they still existed.

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 plants, which is subject to various operational risks.

Our financial performance depends on the successful operation of our subsidiaries’ geothermal power plants. In connection with such operations, we derived approximately 72.7% of our total revenues for the year ended December 31, 2006 from the sale of electricity. The cost of operation and maintenance and the operating performance of our subsidiaries’ geothermal power 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 project sites;


	•	catastrophic events such as fires, explosions, earthquakes, landslides, floods, releases of hazardous materials, severe storms or similar occurrences affecting our projects or any of the power purchasers or other third parties providing services to our projects; 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 projects or reduce the overall generating capacity of our projects and could significantly reduce or entirely eliminate the revenues generated by one or more of our projects, 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 2006, we had to retube old heat exchanger pipes in our Mammoth complex. 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 is subject to geological risks and uncertainties, which may result in decreased performance or increased costs for our projects.

Table of Contents

Our business involves the exploration, development and operation of geothermal energy resources. These activities are subject to uncertainties, which vary among different geothermal reservoirs and are in some respects similar to those typically associated with oil and gas exploration, development and exploitation, such as dry holes, uncontrolled releases and pressure and temperature decline, all of which can increase our operating costs and capital expenditures or reduce the efficiency of our power plants. Prior to our acquisition of the Steamboat Hills project, one of the wells related to the project experienced an uncontrolled release. In addition, the high temperature and high pressure in the Puna project’s geothermal energy resource requires special reservoir management and monitoring. Further, since the commencement of their operations, several of our projects have experienced geothermal resource cooling in the normal course of operations. Because geothermal reservoirs are complex geological structures, we can only estimate their geographic area and sustainable output. The viability of geothermal projects depends on different factors directly related to the geothermal resource, such as the heat content (the relevant composition of temperature and pressure) of the geothermal reservoir, the useful life (commercially exploitable life) of the reservoir and operational factors relating to the extraction of geothermal fluids. Our geothermal energy projects may suffer an unexpected decline in the capacity of their respective geothermal wells and are exposed to a risk of geothermal reservoirs not being sufficient for sustained generation of the electrical power capacity desired over time. In addition, we may fail to find commercially viable geothermal resources in the expected quantities and temperatures, which would adversely affect our development of geothermal power projects.

Another aspect of geothermal operations is the management and stabilization of subsurface impacts caused by fluid injection pressures. In the case of the geothermal resource supplying the Heber 1 project and the Heber 2 project, which we refer to collectively as the ‘‘Heber projects’’, and the Gould project (a new power plant at the site of the Heber projects consisting of two Ormat Integrated Two Level Units (ITLU)), 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 and Gould projects’ 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, geothermally active areas, such as the areas in which our projects are located, are subject to frequent low-level seismic disturbances. Serious seismic disturbances are possible and could result in damage to our projects or equipment or degrade the quality of our geothermal resources to such an extent that we could not perform under the power purchase agreement for the affected project, 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.

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. Our success in developing a particular project is contingent upon, among other things, negotiation of satisfactory engineering and construction agreements and power purchase agreements, 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 power purchase agreement, 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.

Table of Contents

Currently, we have power plants under development or construction in the United States, Kenya, and China, 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;

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 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, 2006, we had approximately $512.2 million of total consolidated indebtedness (including indebtedness to our parent company in the amount of $140.2 million), of which approximately $370.0 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 and capital market conditions, credit availability from banks, investor confidence, the continued success of current projects, the credit quality of the projects being financed, the political situation in the country where the project 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 projects 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 projects 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 projects.

We have substantial operations outside of the United States that generated revenues in the amount of $95.4 million for the year ended December 31, 2006, which represented 35.5% 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 projects in the

Table of Contents

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 projects that we may develop or acquire, thus limiting our ability to control the development, construction and operation of such projects. Our foreign operations are also subject to significant political, economic and financial risks, which vary by country, and include:


	•	changes in government policies or personnel;


	•	changes in general economic conditions;


	•	restrictions on currency transfer or convertibility;


	•	changes in labor relations;


	•	political instability and civil unrest;


	•	changes in the local electricity market;


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


	•	expropriation and confiscation of assets and facilities.

In particular, the Philippines is in the midst of an ongoing privatization of the electric industry, and 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 existing Leyte and Zunil projects and the Amatitlan project (Leyte in the Philippines and Zunil and Amatitlan in Guatemala) currently under construction if, for example, they result in changes to the prevailing tariff regime or in the identity and creditworthiness of our power purchasers. In Nicaragua, Union Fenosa, one of the electric utilities, has been experiencing difficulties adjusting the tariffs charged to its customers, thus effecting Union Fenosa’s ability to pay for electricity its purchase from power generators. This may adversely affect our Momotombo project. 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 independent power producers, to lower their tariffs. In addition, Kenya’s government is considering a further restructuring and privatization of the electricity industry and may divide Kenya Power and Lighting Co. Ltd., the power purchaser for our Olkaria III project, into separate entities and then privatize one or more of such resulting entities. Any break-up and potential privatization of Kenya Power and Lighting Co. Ltd. may adversely affect our Olkaria III project. Although we generally obtain political risk insurance in connection with our foreign projects, 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 project 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 projects and foreign manufacturing operations expose us to risks related to fluctuations in currency rates, which may reduce our profits from such projects 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 projects and foreign manufacturing operations, and may limit or diminish the amount of cash and income that we receive from such foreign projects and operations.

A significant portion of our net revenue is attributed to payments made by power purchasers under power purchase agreements. The failure of any such power purchaser to perform its obligations under

Table of Contents

the relevant power purchase agreement or the loss of a power purchase agreement 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 power purchase agreements. Southern California Edison, Hawaii Electric Light Company and Sierra Pacific Power Company have accounted for 30.0%, 15.1% and 12.8%, respectively, of our revenues for the year ended December 31, 2006. Neither we nor any of our affiliates make any representations as to the financial condition or creditworthiness of any purchaser under a power purchase agreement, and nothing in this annual report should be construed as such a representation.

There is a risk that any one or more of the power purchasers may not fulfill their respective payment obligations under their power purchase agreements. For example, as a result of the energy crisis in California, Southern California Edison withheld payments it owed under various of its power purchase agreements with a number of power generators (such as the Ormesa, Heber, and Mammoth projects) payable for certain energy delivered between November 2000 and March 2001 under such power purchase agreements until March 2002. If any of the power purchasers fails to meet its payment obligations under its power purchase agreements, it could materially and adversely affect our business, financial condition, future results and cash flow.

In connection with the power purchase agreements for the Ormesa project, Southern California Edison has expressed its intent not to pay the contract rate for the power supplied by the GEM 2 and GEM 3 plants to the Ormesa project. Southern California Edison contends that California ISO real-time prices should apply, while management believes that SP-15 prices quoted by NYMEX should apply. According to Southern California Edison’s estimation, the amount under dispute is approximately $2.5 million. The parties have signed an Interim Agreement; whereby Southern California Edison will continue procure the GEM 2 and GEM 3 power at the current energy rate of 5.37 cents/ kWh until May 1, 2007. In addition, a long-term power purchase agreement is expected to be entered into for the GEM 2 and GEM 3 power. The negotiations of the long-term power purchase agreement are still under way and there is no guarantee that it will be successfully completed.

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 projects receive higher capacity payments under the relevant power purchase agreements during the summer months, and due to the generally higher short run avoided costs in effect during the summer months. Some of our other projects 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 power purchase agreements with investor-owned electric utilities in states that have renewable portfolio standards, the failure to supply the contracted capacity and energy thereunder may result in the imposition of penalties.

Under the Burdette, Desert Peak 2, Galena 2, Galena 3, Carson Lake and Buffalo Valley power purchase agreements, 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 power purchase agreement and which such power purchaser is forced to obtain from an alternate source. One of the six power purchase agreements was in commercial operation in 2006 and to date the shortfall amount has not been material. Measured against our revenues from the sale of electricity for the year ended December 31, 2006 and assuming no other changes in our revenues, the revenues from such agreements constitute, collectively, less than 4% of our total revenues from the sale of electricity. In addition, we may be required to make payments to the relevant power purchaser in an amount equal

Table of Contents

to its replacement costs relating to any renewable energy credits we do not provide as required under the relevant power purchase agreement. 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 power purchase agreements, all of which could materially and adversely affect our business, financial condition, future results and cash flow. With respect to certain of our power purchase agreements, we may also be required to pay liquidated damages to our power purchaser if the relevant project does not maintain availability of at least 85% during applicable peak periods. The maximum aggregate amount of such liquidated damages for the Steamboat 2 and Steamboat 3 power purchase agreements would be approximately $1.5 million for each project.

The short run avoided costs for our power purchasers may decline, which would reduce our project revenues and could materially and adversely affect our business, financial condition, future results and cash flow.

Under the power purchase agreements for our projects 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 2007 and, recently, has been fixed again through April 2012, and thereafter will be based on Southern California Edison’s short run avoided costs, as determined by the California Public Utilities Commission. These short run avoided costs may vary substantially on a monthly basis, and are expected to be based primarily on natural gas prices for gas delivered to California as well as other factors. The levels of short run avoided cost prices paid by Southern California Edison may decline following the expiration date of the settlement agreements, which in turn would reduce our project revenues derived from Southern California Edison under our power purchase agreements and could materially and adversely affect our business, financial condition, future results and cash flow.

If any of our domestic projects 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 projects are Qualifying Facilities pursuant to the Public Utility Regulatory Policies Act of 1978, as amended, which we refer to as PURPA, which largely exempts the projects from the Federal Power Act, which we refer to as FPA, and certain state and local laws and regulations regarding rates and financial and organizational requirements for electric utilities.

PUHCA was repealed on February 8, 2006. If any of our domestic projects were to lose its Qualifying Facility status, such project 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 projects could require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility.

In addition, pursuant to the FPA, the 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 project were to lose its Qualifying Facility status, it would become a public utility under the FPA, and the rates charged by such project pursuant to its power purchase agreements would be subject to the review and approval of the FERC. The FERC, upon such review, may determine that the rates currently set forth in such power purchase agreements are not appropriate and may set rates that are lower than the rates currently charged. In addition, the FERC may require that some or all of our domestic projects refund amounts previously paid by the relevant power purchaser to such project. Such events would likely result in a decrease in our future revenues or in an obligation to disgorge revenues previously received from our domestic projects, either of which would have an adverse effect on our revenues. Even if a project does not lose its Qualifying Facility status, pursuant to a final rule

Table of Contents

issued by FERC on February 2, 2006, if a project’s power purchase agreement is terminated or otherwise expires, that project 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 power purchase agreement, to cease taking and paying for electricity from the relevant project 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 power purchase agreements, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our projects. 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 project 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 projects, which would enable the lenders to exercise their remedies and enforce the liens on the relevant project.

Pursuant to the Energy Policy Act of 2005, the FERC was also given authority to prospectively lift the mandatory obligation of a utility under PURPA to purchase the electricity from a Qualifying Facility if the utility operates in a workably competitive market. Existing power purchase agreements between a Qualifying Facility and a utility are not affected. The FERC recently issued a final rule, which could eliminate a utility’s mandatory purchase obligation from Qualifying Facilities in certain regions of the country. The regions do not include areas in which our domestic projects 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. In this rule, the FERC expressly noted that the California Independent System Operator (CAISO) has satisfied one but not all of the criteria for relief from the mandatory purchase obligation. If the utilities in the regions in which our domestic projects operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from the project in the region under Federal law upon termination of the existing power purchase agreement or with respect to new projects, which could have an adverse effect on our revenues.

Our financial performance is significantly dependent on the successful operation of our projects, which is subject to changes in the legal and regulatory environment affecting our projects .

All of our projects 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 projects. The structure of federal and state 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.

The federal government also encourages production of electricity from geothermal resources through certain tax subsidies. We are permitted to claim in our consolidated federal tax returns either an investment tax credit for approximately 10% of the cost of each new geothermal power plant or ‘‘production tax credits’’, which in 2006 was 1.9 cents per kWh and is adjusted annually for inflation, on the first ten years of electricity output. (Production tax credits can only be claimed on new plants put into service between October 23, 2004 and December 31, 2008.) We are also permitted to deduct most of the cost of the power plant as ‘‘depreciation’’ over five years on an accelerated basis. The fact that the deductions are accelerated means that more of the cost is deducted in the first few years than during the remainder of the depreciation period. In addition, we have the ability to transfer the value of these tax incentives when we are not in a position to use them directly. For instance, energy credits can be transferred through lease financing, and production tax credits may be transferred by bringing in another company who can use them as a partner in the project.

Table of Contents

President Bush has made it a central theme of his second term to simplify the U.S. tax code. Among the options that may be under consideration are replacing or supplementing the corporate income tax with a value-added-tax, stripping away many tax subsidies, and eliminating taxes on interest, dividends and other returns to capital. Significant tax reform has the potential to have a material effect on our business, financial condition, future results and cash flow. It could reduce or eliminate the value that geothermal companies receive from the current tax subsidies. Any restrictions or tightening of the rules for lease or partnership transactions — whether or not part of major tax reform — could also materially affect our business, financial condition, future results and cash flow.

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

The costs of compliance with environmental laws and of obtaining and maintaining environmental permits and governmental approvals required for construction and/or operation, which currently are significant, may increase in the future and could materially and adversely affect our business, financial condition, future results and cash flow; any non-compliance with such laws or regulations may result in the imposition of liabilities which could materially and adversely affect our business, financial condition, future results and cash flow.

Our projects 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 projects 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 projects 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 projects. 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 projects under construction or enhancement. In addition, a nearby municipality has informed our Amatitlan project 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 projects under construction or enhancement and the Amatitlan project, 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 projects.

Our projects 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 projects 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 projects, 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 projects 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.

Table of Contents

We believe that at one time there may have been a gas station located on the Mammoth project site, but because of significant surface disturbance and construction since that time further physical evaluation 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 may adversely and materially affect our operations and revenues.

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

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


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


	•	inability to retain key personnel of the acquired companies;


	•	risks associated with unanticipated events or liabilities; and


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

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

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

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

The existence of a prolonged force majeure event or a forced outage affecting a project 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 project experiences an occurrence resulting in a force majeure event, our subsidiary that owns that project would be excused from its obligations under the relevant power purchase agreement. However, the relevant power purchaser may not be required to make any capacity and/or energy payments with respect to the affected project or plant so long as the force majeure event continues and, pursuant to certain of our power purchase agreements, will have the right to prematurely terminate the power purchase agreement. 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 project, and if as a result the project fails to attain certain performance requirements under certain of our power purchase agreements, the purchaser may have the right to

Table of Contents

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 power purchase agreement. As a consequence, we may not receive any net revenues from the affected project or 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 Imperial Irrigation District 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 Imperial Irrigation District experiences a force majeure event or a forced outage which prevents it from transmitting the electricity from the Heber 1 and 2 projects or the Ormesa project 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 project so long as such force majeure event or forced outage continues. Our revenues for the year ended December 31, 2006, from the projects utilizing the Imperial Irrigation District transmission system, were approximately $80.7 million. The impact of such force majeure would depend on the duration thereof, with longer outages resulting in greater revenue loss.

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

Most of our geothermal resource leases are for a fixed primary term, and then continue for so long as geothermal resources are extracted in ‘‘commercial quantities’’ or pursuant to other terms of extension. The land covered by some of our leases is undeveloped and has not yet produced geothermal resources in ‘‘commercial quantities’’. Leases that cover land which remains undeveloped and does not produce, or does not continue to produce, geothermal resources in commercial quantities and leases that we allow to expire, will terminate. In the event that a lease is terminated and we determine that we will need that lease once the applicable project 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, all of which may not be possible or could result in increased cost to us, which could materially and adversely affect our business, financial condition, future results and cash flow.

Our Bureau of Land Management leases may be terminated if we fail to comply with any of the provisions of the Geothermal Steam Act of 1970 or if we fail to comply with the terms or stipulations of such leases, which may materially and adversely affect our business and operations.

Pursuant to the terms of our Bureau of Land Management (which we refer to as BLM) leases, we are required to conduct our operations on BLM-leased land in a workmanlike manner and in accordance with all applicable laws and BLM directives and to take all mitigating actions required by the BLM to protect the surface of and the environment surrounding the relevant land. Additionally, certain BLM leases contain additional requirements, some of which relate to the mitigation or avoidance of disturbance of any antiquities, cultural values or threatened or endangered plants or animals, the payment of royalties for timber and the imposition of certain restrictions on residential development on the leased land. In the event of a default under any BLM lease, or the failure to comply with such requirements, or any non-compliance with any of the provisions of the Geothermal Steam Act of 1970 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.

Table of Contents

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 project 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 projects, 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 projects, thereby affecting our ability to utilize, access, inject and/or transport geothermal resources on or underneath the affected surface areas. In particular, the Heber projects and the Gould project 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 projects and Gould project. 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 projects and Gould project, 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 projects in Nevada may also affect future permitting for geothermal operations relating to those projects. 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 projects.

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

Table of Contents

Bronicki, Dita Bronicki, Hezy Ram, Nadav Amir, Yoram Bronicki and other key employees. The loss of the services of any key employee could materially harm our business, financial condition, future results and cash flow. Although to date we have been successful in retaining the services of senior management and have entered into employment agreements with Lucien Bronicki, Dita Bronicki, Hezy Ram 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 projects have generally been financed through a combination of parent company loans and limited− or non-recourse project finance debt and lease financing. If our project subsidiaries default on their obligations under such limited−or non-recourse debt or lease financing, we may be required to make certain payments to the relevant debt holders and if the collateral supporting such leveraged financing structures is foreclosed upon, we may lose certain of our projects.

Our projects have generally been financed using a combination of parent company loans and limited or non-recourse project finance debt or lease financing. Non-recourse project finance debt or lease financing refers to financing arrangements that are repaid solely from the project’s revenues and are secured by the project’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 project, to provide limited financial support for the project 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 projects, 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 projects) 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 project 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 photovoltaic (solar) 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 projects may be significantly impaired.

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

We have identified recovered energy-based power generation as a significant market opportunity for us. Demand for our recovered energy-based power generation units may not materialize or grow at the levels that we expect. We currently face competition in this market from manufacturers of conventional steam turbines and may face competition from other related technologies in the future.

Table of Contents

If this market does not materialize at the levels that we expect, such failure may materially and adversely affect our business, financial condition, future results and cash flow.

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

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

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

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

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

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

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

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

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

Operations in Israel accounted for approximately 24.1%, 25.2% and 25.6% of our operating expenses in the year ended December 31, 2006, 2005 and 2004, respectively. Political, economic and security conditions in Israel directly affect our operations. Since the establishment of the State of Israel in 1948, a number of armed conflicts have taken place between Israel and its Arab neighbors, and the continued state of hostility, varying in degree and intensity, has led to security and economic problems for Israel. Since October 2000, there has been a significant increase in violence, primarily in the West Bank and Gaza Strip. As a result, negotiations between Israel and representatives of the

Table of Contents

Palestinian Authority have been sporadic and have failed to result in peace. We could be adversely affected by hostilities involving Israel, the interruption or curtailment of trade between Israel and its trading partners, or a significant downturn in the economic or financial condition of Israel. In addition, the sale of products manufactured in Israel may be adversely affected in certain countries by restrictive laws, policies or practices directed toward Israel or companies having operations in Israel.

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

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

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

Our subsidiary, Ormat Systems Ltd., which we refer to as Ormat Systems, has received ‘‘approved enterprise’’ status under Israel’s Law for Encouragement of Capital Investments, 1959, with respect to two of its investment programs. As an approved enterprise, our subsidiary is exempt from Israeli income taxes with respect to revenues derived from the approved investment program for a period of two years commencing on the year it first generates profits from the approved investment program, and thereafter such revenues are subject to a reduced Israeli income tax rate of 25% for an additional five years. These benefits are subject to certain conditions set forth in the certificate of approval from Israel’s Investment Center, which include, 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 Investment Center. 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 financial condition, future results and cash flow. If Ormat Systems distributes dividends out of revenues derived during the tax exemption period from the approved 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 products 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. 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.

Table of Contents

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

We are a holding company and our revenues depend substantially on the performance of our subsidiaries and the projects 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 projects, such as the Mammoth project, there may be certain additional restrictions on dividend distributions pursuant to our agreements with our partners. Further, if we elect to receive distributions of earnings from our foreign operations, we may incur United States taxes on account of such distributions, net of any available foreign tax credits. In all of the foreign countries where our existing projects 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, President 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 Etty Rosner our Vice President — Contract Administrator and Corporate Secretary 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 64.0% of our common stock. Bronicki Investments Ltd. holds approximately 28.12% of the outstanding shares of common stock of Ormat Industries Ltd. as of February 28, 2007 (27.50% 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 products 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.

Table of Contents

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

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


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


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


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


	•	announcements of significant contracts by us or our competitors;


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


	•	loss of one or more of our significant customers;


	•	legislation;


	•	changes in market valuation or earnings of our competitors;


	•	the trading volume of our common stock; and


	•	general economic conditions.

In addition, the stock market in general, and the New York Stock Exchange 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 64% 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 Securities and Exchange Commission 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,

Table of Contents

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 Sarbanes-Oxley Act of 2002 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 Sarbanes-Oxley Act of 2002 (the SOX Act). The SOX Act contains a variety of provisions affecting public companies, including but not limited to, corporate governance requirements, our relationship with our auditors, evaluation of our internal disclosure controls and procedures and evaluation of our internal control over financial reporting. See Management’s Report on Internal Control over Financial Reporting and Item 9A. — ‘‘Controls and Procedures’’.

ITEM 1B. UNRESOLVED STAFF COMMENTS

On December 29, 2006, we received a comment letter from the staff of the Division of Corporation Finance of the SEC, with respect to our annual report on Form 10-K for the year ended December 31, 2005. We responded to the staff’s comments in a letter dated January 29, 2007. We believe that we have resolved all of the staff’s comments, with the exception of one staff comment relating to the accounting treatment in the statement of cash flows and in the statement of operations of the lease and lease back transaction of the Puna project. . Our response to the staff included a detailed discussion of relevant accounting authority and our analysis undertaken in reaching a decision to so present and account for the Head Lease. On March 9, 2007, we received a follow up letter from the staff, asking us for an explanation of our lease out, lease in transactions and our analysis and the accounting authority for our conclusion regarding the accounting treatment of such transactions. As such, this comment remains unresolved. The Company believes that it has properly accounted for the Puna lease transaction in accordance with the provisions of SFAS No. 13, Accounting for Leases .

ITEM 2. PROPERTIES

We currently lease corporate offices at 6225 Neil Road, Reno, Nevada 89511-1136. We also occupy an approximately 66,000 square meter office and manufacturing facility located in the Industrial Park of Yavne, Israel, which we sublease from Ormat Industries. See ‘‘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 are adequate for our operations as currently conducted. If additional facilities are required, we believe that we could obtain additional facilities at commercially reasonable prices.

Each of our projects 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 2006, other than as described below.

As a result of our acquisition of the Steamboat 1 and 1A plants, our subsidiary Steamboat Geothermal LLC has become a party to litigation pending in the Second Judicial District Court in Washoe County, Nevada with Geothermal Development Associates and Delphi Securities, Inc. In April 2002, these plaintiffs initiated a lawsuit against the former owner and operator of the Steamboat

Table of Contents

1/1A project. The plaintiffs dispute amounts owed to them pursuant to an agreement, dated July 14, 1985, pursuant to which Geothermal Development Associates assigned all of its right, title, and interest in the subject geothermal leasehold property in exchange for a net operating royalty interest in the revenues of the Steamboat 1 plant. The plaintiffs claim entitlement to damages based upon the following three allegations, which we deny: (i) that the actions of the former owner in developing the Steamboat 1A plant have decreased the output of the Steamboat 1 plant; (ii) that general, administrative, and corporate expenses included by the former owner in the calculation of the net royalty amount were overstated for the years 2000 and 2001; and (iii) that, in addition to its royalty interest in the revenues from the Steamboat 1 plant, plaintiffs are entitled to a net revenue royalty interest from the Steamboat 1A plant. The matter was originally set for a trial in September 2003, but the trial date was adjourned in order to allow the plaintiffs to obtain substitute counsel. Initial evidentiary disclosures and discovery requests had been made before the trial was adjourned. No dispositive motions are pending before the Court and the trial date has not been rescheduled. As of December 31, 2005 and January 9, 2006, Steamboat Geothermal LLC entered into a sales, settlement and release agreement and an assignment agreement, respectively, with Woodside Properties LLC, the assignee of 37% of Geothermal Development Associates’ right to net operating revenues, whereby Steamboat Geothermal LLC was assigned 37% of the net operating revenues of Steamboat 1 in partial settlement of the above mentioned dispute with Geothermal Development Associates and Delphi Securities, Inc. The plaintiffs also assert that, in addition to the amounts they claim are owed to them, they are entitled to interest on those amounts, as well as a reasonable net operating royalty payment from our Burdette project. We believe that such assertion is without merit, and that any outcome of such litigation or any settlement discussions will not have a material impact on our results of operations. On November 14, 2006, the parties agreed to dismiss plaintiff Delphi Securities, Inc. from the case with prejudice. The case is scheduled for mediation on April 10-11, 2007.

In connection with the power purchase agreements for the Ormesa project, Southern California Edison has expressed its intent not to pay the contract rate for the power supplied by the GEM 2 and GEM 3 plants to the Ormesa project. Southern California Edison contends that California ISO real-time prices should apply, while management believes that SP-15 prices quoted by NYMEX should apply. According to Southern California Edison’s estimation, the amount under dispute is approximately $2.5 million. The parties have signed an interim agreement; whereby Southern California Edison will continue to procure the GEM 2 and GEM 3 power at the current energy rate of 5.37 cents/kWh until May 1, 2007. In addition, a long-term power purchase agreement is expected to be entered into for the GEM 2 and GEM 3 power. The negotiations in connection with the long-term power purchase agreement are still under way and there is no guarantee that such negotiations will be successfully completed. Management believes that such settlement agreement will not have a material financial impact on us.

One of our subsidiaries, Ormat Inc., is a party in a third-party complaint originally filed on November 15, 2005 by Lacy M. Henry and Judy B. Henry (the Henrys) in a bankruptcy proceeding in the United States Bankruptcy Court for the Eastern District of North Carolina. The Henrys are debtors in a Chapter 11 bankruptcy filed in the Bankruptcy Court. The Henrys were the sole shareholders of MPS Generation, Inc. (MPSG). We entered into a supply contract with MPSG dated as of December 29, 2003, under which we were retained as a subcontractor to produce four waste heat energy converters for a project for which MPSG had entered into a contract with Basin Electric Power Cooperative (Basin). Basin filed a lawsuit on February 24, 2005 against, among others, MPSG and the Henrys in the United States District Court for the District of North Dakota, alleging various causes of action including breach of contract, actual and constructive fraud, and conversion, and demanding the piercing of MPSG’s corporate veil to establish the personal liability of the Henrys for MPSG’s debts. On September 15, 2005, Basin filed a complaint commencing the bankruptcy adversary proceeding, seeking a determination that the claims which Basin alleged against the Henrys in the North Dakota lawsuit were not dischargeable. On November 15, 2005, the Henrys answered Basin’s complaint in the bankruptcy proceeding and also filed a third-party complaint against us, alleging that to the extent the Henrys are found personally liable to Basin for MPSG’s debts, the Henrys have claims against us for breach of contract/breach of warranty, tortious interference with contract, unfair

Table of Contents

or deceptive trade practices and fraud. The Henrys alleged damages in excess of $100 million. On December 15, 2005, we filed an answer denying the Henrys’ claims and asserting counterclaims against the Henrys. Our subsidiary filed a motion to dismiss the Henrys’ claims on January 31, 2006. On March 21, 2006, Basin filed an Amended Complaint in the bankruptcy proceeding, consolidating the causes of action it brought in the North Dakota lawsuit. In their answer to Basin’s Amended Complaint, the Henrys raised the same third party claims against our subsidiary. On May 11, 2006, the Bankruptcy Court entered an order denying our subsidiary’s motion to dismiss the Henrys’ claims against it, but staying the Henrys’ litigation against our subsidiary pending the resolution of Basin’s alter ego claims against the Henrys. In its answer to Basin’s Amended Complaint, MPSG asserted third party claims against our subsidiary similar to those claims raised by the Henrys. We believe that we have no liability to the Henrys or to MPSG and intend to defend vigorously against the Henrys’ and MPSG’s claims in the bankruptcy proceeding. A trial on all issues raised in the bankruptcy proceeding is scheduled to begin in September 2007 in the Bankruptcy Court.

From time to time, we (including our subsidiaries) are a party to various other lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our (and their) business. These actions typically seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to such lawsuits, claims and proceedings, we accrue reserves in accordance with U.S. generally accepted accounting principles. We do not believe that any of these proceedings, individually or in the aggregate, would materially and adversely affect our business, financial condition, future results or cash flows.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of our security holders during the quarter ended December 31, 2006.

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 New York Stock Exchange 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. The approximate number of holders of record of our common stock was 8 on February 28, 2007. On February 28, 2007, our stock’s closing price as reported on the New York Stock Exchange was $38.82 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:

Date Declared

Dividend
Amount per Share

Record Date

Payment Date

March 22, 2005

0.03

April 4, 2005

April 18, 2005

May 10, 2005

0.03

May 23, 2005

June 6, 2005

August 11, 2005

0.03

August 22, 2005

September 1, 2005

November 9, 2005

0.03

November 29, 2005

December 6, 2005

March 7, 2006

0.03

March 28, 2006

April 4, 2006

May 9, 2006

0.04

May 23, 2006

May 30, 2006

August 6, 2006

0.04

August 23, 2006

August 30, 2006

November 7, 2006

0.04

November 30, 2006

December 13, 2006

February 27, 2007

0.07

March 21, 2007

March 29, 2007

High/Low Stock Prices:

Ormat Technologies, Inc. (ORA) — High and Low Prices for the years 2005 and 2006, and from January 1 until February 28, 2007:


	First Quarter 2005			Second Quarter 2005			Third Quarter 2005			Fourth Quarter 2005			First Quarter 2006			Second Quarter 2006			Third Quarter 2006			Fourth Quarter 2006			January 1 to February 28, 2007
High:		$	16.50		$	19.20		$	24.10		$	29.10		$	43.42		$	40.54		$	38.59		$	40.98		$	44.59
Low:		$	14.50		$	13.88		$	18.25		$	18.80		$	27.75		$	31.64		$	31.75		$	32.01		$	37.11

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, 2006 for our common stock, as compared to the Standard and Poor’s Composite 500 Index, and a peer group.


	11/11/2004			12/31/2004			12/31/2005			12/31/2006
Ormat Technologies, Inc.		$	100		$	109		$	174		$	245
Standard & Poor’s Composite 500 Index		$	100		$	108		$	111		$	126
IPP Peers*		$	100		$	113		$	144		$	210
Renewable Peers*		$	100		$	117		$	236		$	220


*	Independent Power Producer (IPP) Peers are The AES Corporation, NRG Energy Inc. and International Power PLC Renewable energy (Renewable) Peers are Acciona S.A., Evergreen Solar Inc. and Energy Conversion Devices 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’’.

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

None.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth our selected consolidated financial data for the years ended and at the dates indicated. We have derived the selected consolidated financial data for the years ended December 31, 2006, 2005 and 2004 and as of December 31, 2006 and 2005 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, 2003 and 2002, and as of December 31, 2004, 2003 and 2002 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 Part II Item 8 of this annual report.


	Years Ended December 31,
	2006				2005				2004				2003				2002
	(in thousands, except per share data)
Statements of Operations Data:
Revenues:
Electricity:
Energy and capacity		$	106,682			$	104,975			$	100,281			$	77,752			$	65,491
Lease portion of energy and capacity			86,115				70,963				58,550				—				—
Lease income			2,686				1,431				—				—				—
Total Electricity			195,483				177,369				158,831				77,752				65,491
Products			73,454				60,623				60,399				41,688				20,138
Total revenues			268,937				237,992				219,230				119,440				85,629
Cost of revenues:
Electricity:
Energy and capacity			77,768				70,328				63,300				46,726				33,482
Lease portion of energy and capacity			41,345				30,215				26,442				—				—
Lease expense			5,243				3,072				—				—				—
Total Electricity			124,356				103,615				89,742				46,726				33,482
Products			51,215				45,236				46,336				29,494				17,293
Total cost revenues			175,571				148,851				136,078				76,220				50,775
Gross margin:			93,366				89,141				83,152				43,220				34,854
Operating expenses (income):
Research and development expenses			2,983				3,036				2,175				1,391				1,503
Selling and marketing expenses			10,361				7,876				7,769				7,087				6,051
General and administrative expenses			18,094				14,320				11,609				9,252				7,073
Gain on sale of geothermal resource rights			—				—				(845	)			—				—
Operating income			61,928				63,909				62,444				25,490				20,227
Other income (expense):
Interest income			6,560				4,308				1,316				607				609
Interest expense			(30,961	)			(55,317	)			(42,785	)			(8,120	)			(6,179	)
Foreign currency translation and
transaction loss			(704	)			(439	)			(146	)			(316	)			(323	)
Other non-operating income			694				512				112				464				1,195
Income from continuing operations
before income taxes, minority
interest and equity in income of investees			37,517				12,973				20,941				18,125				15,529
Income tax provision			(6,403	)			(4,690	)			(6,609	)			(2,506	)			(6,135	)
Minority interest in earnings of subsidiaries			(813	)			—				(108	)			(519	)			(1,194	)
Equity in income of investees			4,146				6,894				3,567				559				314
Income from continuing operations			34,447				15,177				17,791				15,659				8,514
Discontinued operations:
Loss from operations of discontinued activities in Kazakhstan			—				—				—				—				(3,114	)
Loss on sale of Kazakhstan operations			—				—				—				—				(6,444	)
Income (loss) before cumulative effect of change in accounting principle			34,447				15,177				17,791				15,659				(1,044	)
Cumulative effect of change in accounting principle (net of tax benefit of $125,000)			—				—				—				(205	)			—
Net income (loss)		$	34,447			$	15,177			$	17,791			$	15,454			$	(1,044	)


	Years Ended December 31,
	2006			2005			2004			2003				2002
	(in thousands, except per share data)
Basic earnings (loss) per share:
Income from continuing operations		$	1.00		$	0.48		$	0.72		$	0.67			$	0.37
Loss from discontinued operations			—			—			—			—				(0.41	)
Cumulative effect of change in accounting principle			—			—			—			(0.01	)			—
Net income (loss)		$	1.00		$	0.48		$	0.72		$	0.66			$	(0.04	)
Diluted earnings (loss) per share:
Income from continuing operations		$	0.99		$	0.48		$	0.72		$	0.67			$	0.37
Loss from discontinued operations			—			—			—			—				(0.41	)
Cumulative effect of change in accounting principle			—			—			—			(0.01	)			—
Net Income (loss)		$	0.99		$	0.48		$	0.72		$	0.66			$	(0.04	)
Weighted average number of shares used in computation of earnings (loss) per share:
Basic			34,593			31,563			24,806			23,214				23,214
Diluted			34,707			31,609			24,806			23,214				23,214
Cash dividend per share declared during the year		$	0.1500		$	0.1200		$	0.1025		$	—			$	—
Balance Sheet Data (at end of year):
Cash and cash equivalents		$	20,254		$	26,976		$	36,750		$	8,873			$	36,684
Working capital (deficit)			34,429			36,616			50,341			2,677				(79,853	)
Property, plant and equipment, net (including construction-in process)			793,164			620,091			527,003			379,133				180,118
Total assets			1,160,102			914,480			850,088			543,138				287,378
Long-term debt (including current portion)			372,009			365,539			384,515			260,488				95,807
Notes payable to Parent (including current portion)			140,153			171,805			193,852			177,004				—
Stockholders’ equity			440,794			182,259			167,914			36,975				27,837

Table of Contents


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

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

General

Overview

We are a leading vertically integrated company engaged in the geothermal and recovered energy power business. We design, develop, build, own and operate clean, environmentally friendly geothermal and recovered energy-based power plants using equipment that we design and manufacture. In addition, we sell the equipment we design and manufacture for geothermal electricity generation, recovered energy-based electricity generation, and other equipment for electricity generation to third parties. Our operations consist of two business segments. The first consists of the sale of electricity from our power plants, which we refer to as the Electricity Segment. The second consists of the design, manufacturing and sale of equipment for electricity generation, the installation thereof and the provision of services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy power plants, which we refer to as the Products Segment.

Our Electricity Segment mainly consists of our investment in power plants producing electricity from geothermal resources and, as of recently, from recovered energy resources. 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. Our Products Segment consists of the design, manufacture and sale of equipment that generates electricity, principally from geothermal and recovered energy resources, but also using other fuel sources as well. Our Products Segment also includes, to the extent requested by our customers, the installation of our equipment and other related power plant installations and the provision of services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy power plants. For the year ended December 31, 2006, our Electricity Segment represented approximately 72.7% of our total revenues, while our Products Segment represented approximately 27.3% of our total revenues during such year.

During the year ended December 31, 2006, total Electricity Segment revenues from the sale of electricity by our consolidated power plants (including revenues derived from the Zunil project, which was consolidated as of March 13, 2006) were $195.5 million. In addition, revenues from our 50% ownership of the Mammoth Project and from our 80% ownership of the Leyte Project for the year ended December 31, 2006 were $18.6 million. This additional data is a Non-Generally Accepted Accounting Principles (Non-GAAP) financial measure as defined by the SEC. There is no comparable GAAP measure. Management believes that such Non-GAAP data is useful to the readers as it provides a more complete view on the scope of the activities of the power plants that we operate. Our investments in the Mammoth and Leyte projects are accounted for in our consolidated financial statements under the equity method and the revenues are not included in our consolidated revenues for the year ended December 31, 2006.

Our Electricity Segment operations are conducted in the United States and throughout the world. Since January 1, 2001, we have completed various acquisitions of geothermal power plants with an aggregate acquisition cost, net of cash received, of $526.7 million. In the year ended December 31,

Table of Contents

2006, we increased our net ownership interest in generating capacity by 19 MW through the acquisition of an additional 79.0% ownership interest in the Zunil project in Guatemala, thereby increasing our ownership interest in that project to 100%, as a result of which the project is now fully consolidated. In addition, we increased our net ownership interest in generating capacity by 32 MW through new construction, which includes our first four REG plants completed in the fourth quarter of 2006. We currently own or control as well as operate geothermal projects in the United States, Guatemala, Kenya, Nicaragua and the Philippines.

Our Products Segment operations are also conducted in the United States and throughout the world. During the year ended December 31, 2006, revenues attributable to our Products Segment were $73.5 million.

We have identified recovered energy-based power generation as a significant market opportunity for us in the United States and throughout the world. We expect that recovered energy generation projects will increase our revenues in both the Electricity Segment and the Products Segment.

During the year ended December 31, 2006, we recognized revenues in our Products Segment of approximately $25.0 million from REG compared to $8.5 million during the year ended December 31, 2005. During the year ended December 31, 2006 we received purchase orders for the supply and construction of REG plants in a total amount of $36.6 million, out of which we recognized revenues in the amount of $8.5 million in the year ended December 31, 2006. Our Electricity Segment is characterized by relatively predictable revenues generated by our power plants pursuant to long-term power purchase agreements, with terms which are generally up to 20 years. The price for electricity under all of the power purchase agreements is effectively a fixed price, except in the case of the power purchase agreement of the Puna project, which has a variable energy rate based on the local utility’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). 81.2% of the electricity revenues generated in the year ended December 31, 2006, was derived from contracts with fixed energy rates, and therefore such revenues were not affected by the fluctuations in energy commodity prices.

Revenues attributable to our Products Segment, which are based on the sale of equipment and the provision of various services to our customers, 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, our management typically focuses on the internal rate of return of the relevant investment, relevant technical and geological matters and other relevant business considerations. Additionally, as part of our Electricity Segment, our management evaluates our operating projects based on the performance of such projects in terms of revenues and expenses in contrast to projects that are under development, which our management evaluates based on costs attributable to each such project. By contrast, our management evaluates the performance of our Products Segment based on the timely delivery of our products, performance quality of our products and costs actually incurred to complete customer orders as compared to the costs originally budgeted for such orders.

During the year ended December 31, 2006, our total revenues increased by 13.0% (from $238.0 million to $268.9 million) over the previous year. During the years ended December 31, 2006 and 2005, our U.S. projects generated 1,894,227 MWh and 1,799,072 MWh, respectively, which include our 50% share in the Mammoth project. We were unable to realize fully the aggregate generating capacity of our power plants due to unexpected operational problems that we experienced at some of our plants, such as the Puna and Ormesa projects, and the delay in the commercial operation of the Desert Peak 2 plant, all of which are described in this report.

Table of Contents

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 1990’s, 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 production costs for electricity generated from geothermal resources have become more competitive relative to fossil fuel generation, due to increasing natural gas prices and as a result of newly enacted legislative and regulatory incentives, such as state renewable portfolio standards. 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 the most significant trends affecting our industry today and in the immediate future. The recent relative decline in oil and gas prices does not appear to have impacted the increasing demand for renewable energy. Our operations and the trends that from time to time impact our operations are subject to market cycles.

Although other trends, factors and uncertainties may impact our operations and financial condition, including many that we do not or cannot foresee, we believe that our results of operations and financial condition for the foreseeable future will be affected by the following trends, factors and uncertainties:


	•	In 2005 and 2006, our primary activity has been the implementation of our organic growth through the construction of new projects and enhancements of several of our existing projects, as discussed in Item 1 — ‘‘Business — Our Power Generation Business’’ in this annual report. As a result, growth in revenues and overall generating capacity has been more moderate than the previous two years, which were characterized by significant acquisitions. Nevertheless, we expect that this investment in organic growth will result in a significant increase in our total generating capacity and a corresponding increase in our consolidated revenues as well as in our operating income attributable to our Electricity Segment in 2007, as compared with 2006.


	•	We expect that the increased awareness of climate change may result in significant changes in the business and regulatory environment, which may create business opportunities for us going forward


	•	In the United States, we expect to continue to benefit from the increasing demand for renewable energy as a result of favorable legislation adopted by 23 states and the District of Colombia, including California, Nevada and Hawaii (where we have been active in geothermal development and in which all of our U.S. geothermal projects are located). In each of these states, relevant legislation currently requires 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 create additional opportunities for us to expand existing projects and build new power plants.


	•	On September 27, 2006, the California Global Warming Solutions Act of 2006 (the Act) was signed into law. The Act regulates most sources of greenhouse gas emissions and is expected to result in a reduction of carbon emissions to 1990 levels by 2020, representing a twenty-five percent reduction in greenhouse gas emissions. To accomplish this, the Act provides a framework for greenhouse gas emissions reductions through the use of emissions control technologies and other cost-effective reduction strategies, one of which may involve the use of market-based trading of emissions rights. The California Air Resources Board must adopt standards for implementing the Act by 2011. Although programs under the Act will take some time to develop, its requirements, particularly the creation of a market-based trading mechanism to achieve compliance with emissions caps, should be highly advantageous to in-state energy generating sources that have low carbon emissions such as geothermal energy.

Table of Contents


	•	On September 27, 2006, California also enacted legislation requiring that its renewable portfolio standard of 20% generation from renewable energy resources per year be met by December 2010, ahead of the previous legislative mandated target of December 2017. The California legislature is currently considering an increase to 33% by December 31, 2020.


	•	Outside of the United States, we expect that a variety of governmental initiatives, including 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, will create new opportunities for the development of new projects as well as create additional markets for our remote power units and other products.


	•	In pursuing new orders, we participate in tenders for projects and proposals for installations and identify and monitor markets, which utilize or plan to utilize geothermal energy, and in which geothermal resources are available. We also intend to continue to pursue growth in our recovered energy business, and we expect that the portion of revenues from our recovered energy business as a percentage of the total revenues from our Products Segment will increase.


	•	We expect to continue to generate the majority of our revenues from our Electricity Segment through the sale of electricity from our power plants. All of our current revenues from the sale of electricity are derived from fully-contracted payments under long-term power purchase agreements.


	•	Over the last year, competition from the wind and solar power generation industry has increased. While the current demand for renewable energy is large enough that this increased competition has not impacted our ability to obtain new power purchase agreements, it may create pressure on electricity prices.


	•	The viability of the geothermal resources utilized by our power plants depends on various factors such as the heat content of the geothermal reservoir, useful life of the reservoir (the term during which such geothermal reservoir has sufficient extractable fluids for our operations) and operational factors relating to the extraction of the geothermal fluids. Our geothermal power plants may experience an unexpected decline in the capacity of their respective geothermal wells. 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 operations.


	•	As our power plants age, they may require increased maintenance with a resulting decrease in their availability.


	•	Our foreign operations are subject to significant political, economic and financial risks, which vary by country. Such risks include the ongoing privatization of the electricity industry in the Philippines, the partial privatization of the electricity sector in Guatemala, labor unrest in Nicaragua and the political uncertainty currently prevailing in Kenya. Although we maintain political risk insurance as an attempt to mitigate such risks, such insurance does not provide complete coverage with respect to all such risks.


	•	We continue to experience increases in the cost of raw materials required for our equipment manufacturing activities and equipment used in our power plants. We partially addressed the availability of drilling equipment by purchasing a drilling rig, which we expect will be supplied to us in the first half of 2007. We have experienced an increase in drilling costs and a shortage in drilling equipment, which we believe is the result of the high oil prices resulting in increased drilling activity in the marketplace. We also have experienced, and expect to continue to experience, an increase in construction costs, particularly in the United States, due to rising prices attendant to a significant increase in activities in the construction industry. An increase in such costs may have an adverse effect on our financial condition and results of operations.

Table of Contents


	•	The United States extended a tax subsidy and increased the amount of the tax subsidy for companies that use geothermal steam or fluid to generate electricity as part of the Energy Policy Act of 2005 that became law on August 8, 2005. The tax subsidy is a ‘‘production tax credit’’, which in 2006 was 1.9 cents per kWh and is adjusted annually for inflation. The production tax credit may be claimed on the electricity output of new geothermal power plants put into service by December 31, 2008. Credit may be claimed for ten years on the output from any new geothermal power plants put into service prior to December 31, 2008. We, as the owner of any project that would be put in service during the period ending December 31, 2008, would have to choose between this production tax credit and a 10% investment tax credit.


	•	The Energy Policy Act of 2005, as mentioned above, 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 power purchase agreements. We do not expect this change in law to affect our U.S. projects significantly, as all except one of our current contracts (our Steamboat 1 project, which sells its electricity to Sierra Pacific Power Company on a year-by-year basis) are long-term. FERC has recently issued a final rule that could eliminate the utility’s purchase obligation in four regions of the country. None of those regions includes a state in which our current projects 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. In the final rule, FERC expressly noted that the California Independent System Operator (CAISO) has satisfied one but not all of the criteria for relief from the mandatory purchase obligation. If the utilities in the regions in which our domestic projects operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from the project in the region under Federal law upon termination of the existing power purchase agreement, which could have an adverse effect on our revenues.


	•	On July 21, 2006, the Bureau of Land Management and the Minerals Management Service (each part of the Department of the Interior) issued separate proposed rules intended to implement relevant provisions of the Energy Policy Act of 2005. If adopted as proposed, the proposed rules would revise existing federal regulations, dealing with the general geothermal leasing process for federal land, lease durations, work commitments, annual rental and credit of rental toward royalties, and royalty calculations. Key features of the proposed rules include a requirement that geothermal resources be offered through a competitive lease process; the introduction of a new royalty methodology, calculated on the basis of gross proceeds from the sale of electricity, rather than the ‘‘netback’’ calculation previously in use; the introduction of increased rental payments (that are creditable toward royalties owed), and a new scheme of lease terms and extensions. The proposed rules would also establish ‘‘production incentives’’ for new facilities and qualified expansion facilities that are put into commercial operation by August 8, 2011, in the form of a four-year 50% reduction in royalty from what would otherwise be due. The 50% reduction would apply to all of the electricity generated from a new facility, and to the incremental electricity generated by a qualified expansion facility. The provisions of the proposed rules dealing with fees, rental payments, and royalties would apply to geothermal leases issued after August 8, 2005. However, lessees under leases issued prior to August 8, 2005 may elect to convert their leases to the new regulatory framework. The 60-day period for public comments on the proposed rule has expired, but as of the date of this report, no further regulatory action to codify and implement the proposed rules has been published. We do not expect that such proposed rules will have a material impact on us.

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.

Table of Contents

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 power purchase agreements; 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 power generation from our projects and by unplanned major maintenance activities related to our projects.

Our power purchase agreements generally provide for the payment of capacity payments, energy payments, or both. Generally, capacity payments are payments calculated based on the amount of time that our power plants are available to generate electricity. Some of our power purchase agreements 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 power purchase agreements 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 lease income related to the Puna lease transactions, which are accounted for as operating leases, is included as a separate line item in our Electricity Segment revenues (See ‘‘Liquidity and Capital Resources’’). For management purposes, we analyze such revenue on a combined basis with other revenues in our Electricity Segment.

As required by Emerging Issues Task Force (EITF) Issue No. 01-8, Determining Whether an Arrangement Contains a Lease , we have assessed all of our power purchase agreements agreed to, modified or acquired in business combinations on or after July 1, 2003, and concluded that all such agreements contained a lease element requiring lease accounting. Accordingly, revenue related to the lease element of the agreements is presented as ‘‘lease portion of energy and capacity’’ revenue, with the remaining revenue related to the production and delivery of the energy presented as ‘‘energy and capacity’’ revenue in our consolidated financial statements.

As the lease revenue and the energy and capacity revenues are derived from the same arrangement and both fall within our Electricity Segment, we analyze such revenues, and related costs, on a combined basis for management purposes.

Revenues attributable to our Products Segment are generally less predictable than revenues from our Electricity Segment because larger customer orders for our products are typically a result of our winning tenders 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 Products Segment fluctuate (and at times, extensively) from period to period.

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


	Revenues in Thousands									% of Revenues for Period Indicated
	Year Ended December 31,									Year Ended December 31,
	2006			2005			2004			2006			2005			2004
Revenues
Electricity Segment		$	195,483		$	177,369		$	158,831		72.7	%		74.5	%		72.4	%
Products Segment			73,454			60,623			60,399		27.3	%		25.5	%		27.6	%
Total		$	268,937		$	237,992		$	219,230		100.0	%		100.0	%		100.0	%

Table of Contents

Geographical breakdown of revenues

For the years ended December 31, 2006, 2005, and 2004, respectively, 83.3%, 87.8% and 84.7% of the revenues attributable to our Electricity Segment were generated in the United States.

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


	Revenues in Thousands									% of Revenues for Period Indicated
	Year Ended December 31,									Year Ended December 31,
	2006			2005			2004			2006			2005			2004
United States		$	162,844		$	155,646		$	134,576		83.3	%		87.8	%		84.7	%
Foreign			32,639			21,723			24,255		16.7			12.2			15.3
Total		$	195,483		$	177,369		$	158,831		100.0	%		100.0	%		100.0	%

In the years ended December 31, 2004 and 2005 we did not have material products sales in the United States. In the year ended December 31, 2006 we recognized revenues of $10.5 million in our Products segments from sales in the United States.

Seasonality

The demand for the electricity generated by our domestic projects and the prices paid for such electricity pursuant to some of our power purchase agreements are subject to seasonal variations. The demand for electricity from the Heber 1 and 2 projects, the Mammoth project and the Ormesa project is the highest in the summer months of June through September, because the power purchaser for those projects, Southern California Edison, delivers more electricity to its California markets during such period in order to meet demand for air conditioning and other energy-intensive cooling systems utilized during such summer months. The demand for electricity from the Steamboat complex and the Brady project is more balanced, consisting of both summer and winter peaks that reflect the greater temperature variations in Nevada. The demand for electricity from the Puna project is balanced due to the equatorial temperature in Hawaii (with less pronounced temperature variations during the year). In most of our power purchase agreements in California, the capacity rates payable pursuant to the applicable power purchase agreement are higher in the summer months and as a result we receive higher revenues during such months. In contrast, there are no significant changes in prices during the year payable pursuant to our power purchase agreement for the Puna project and the Nevada projects. 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 as a result of the increase in demand and in prices have a more significant impact on our revenues than that of the higher energy revenues generally generated in winter due to increased efficiency, and as a result our revenues are generally higher in the summer than in the winter.

Breakdown of Expenses

Electricity Segment

The principal expenses attributable to our operating projects include operation and maintenance expenses such as salaries, 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 and, for the California projects, transmission charges, scheduling charges and purchases of sweet water for use in our plant cooling towers. Some of these expenses, such as parts, third-party services and major maintenance, are not incurred on a regular basis, which results in fluctuations in our expenses and our results of operations for individual projects from quarter to quarter. The lease expense related to the Puna lease transactions is included as a separate line item in our Electricity Segment cost of revenues (See ‘‘Liquidity and Capital Resources’’). For management purposes, we analyze such costs on a combined basis with other cost of revenues in our Electricity Segment.

Table of Contents

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 are payments made as compensation for the right to use certain geothermal resources and are included in cost of revenues, and are paid as a percentage of the revenues derived from the associated geothermal rights. For the year ended December 31, 2006, royalties were approximately 3.9% of the Electricity Segment revenues.

Products Segment

The principal expenses attributable to our Products 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 Products Segment, such as a portion of the costs related to labor, utilities and other support services are fixed. As a result, the cost of revenues attributable to our Products Segment, expressed as a percentage of total revenues, fluctuates. Another reason for such fluctuation is that in responding to bids for our products, we price our products and services in relation to existing competition and other prevailing market conditions, which may vary substantially from order to order.

Cash, Cash Equivalents and Marketable Securities

Our cash, cash equivalents and marketable securities as of December 31, 2006 increased to $116.7 million from $70.5 million as of December 31, 2005. This increase is principally due to the combination of the $135.1 million net proceeds from our follow-on offering in April 2006 of 4,025,000 shares of common stock at a price of $37.50 per share, the $92.4 million net proceeds from our sale of 2,500,000 shares of common stock to Lehman Brothers in a block trade in December 2006 at a price of $37.50 per share, and $73.0 million derived from operating activities in the year ended December 31, 2006. During the year ended December 31, 2006, we used $159.5 million of our cash resources to fund capital expenditures and $22.8 million for acquisitions and to repay long-term debt to our parent and to third parties.

Critical Accounting Policies

Our significant accounting policies are more fully described in Note 1 to our audited consolidated financial statements set forth in Part II 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. 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, are recorded based upon output delivered and capacity provided by such power plants at rates specified pursuant to the relevant power purchase agreements. For power purchase agreements agreed to, modified or acquired in business combinations on or after July 1, 2003 (effective date of Emerging Issues Task Force Issue (EITF) No. 01-08, Determining Whether an Arrangement Contains a Lease ), revenues related to the lease element of the power purchase agreements are included as ‘‘lease portion of energy and capacity’’ revenues, with the remaining revenues related to the production and delivery of energy is presented as ‘‘energy and capacity’’. Lease income and lease expense are recognized ratably over the lease periods. Revenues generated from engineering and operating services and sales of products and parts are recorded once the service is provided or product delivery is made, as applicable. Revenues generated from the construction of geothermal and recovered energy power plant equipment and other equipment on behalf of third parties is recognized on the percentage completion method, which is the relationship between costs

Table of Contents


		actually incurred and total estimated costs to completion. Such cost estimate is made by management in part based on prior operations and in part based on specific project characteristics and designs. If management’s estimates utilized with respect to our Products Segment of total estimated costs to completion are inaccurate, then the percentage of completion will also be inaccurate and thus lead management to over or under-estimate the gross margins for our Products Segment. Provisions for estimated losses relating to 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 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.


	•	Property, Plant and Equipment. Property, plant and equipment are stated at cost. All costs associated with the acquisition, development and construction of power plant facilities are capitalized. Major improvements are capitalized and repairs and maintenance (including major maintenance) costs are expensed. We estimate that the useful life of our power plants coincides with the term of the power purchase agreement; however, it is possible that the power plants may last longer than the related power purchase agreement. We periodically re-evaluate the estimated useful life of the power plants, which may result in our revising the useful life to a longer period at a future date.


	•	Impairment of Long-lived Assets and Long-lived Assets to Be Disposed of. Long-lived assets consist of property, plant and equipment, power purchase agreements and unconsolidated investments and are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated future net undiscounted cash flows expected to be generated by the relevant asset. The significant assumptions that we use in estimating our undiscounted future cash flows include: (i) projected generating capacity of the project and rates to be received under the respective power purchase agreements, and (ii) projected operating expenses of the relevant project. If 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 the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. Our assessment regarding the existence of impairment factors is based on market conditions, operational performance and legal factors relating to our business. Our review of existing factors and the resulting appropriate carrying value of our long-lived assets are subject to judgment and estimates that management is required to make. We believe that no impairment exists for our long-lived assets; however, future estimates as to the recoverability of such assets may change based on revised circumstances.


	•	Obligations Associated with the Retirement of Long-Lived Assets. Effective January 1, 2003, we adopted Statement of Financial Accounting Standards (SFAS) No. 143 of the Financial Accounting Standards Board (FASB), Accounting for Obligations Associated with the Retirement of Long-Lived Assets . Pursuant to SFAS No. 143, which was amended by FASB Interpretation (FIN) No. 47, Accounting for Conditional Retirement Obligations, an Interpretation of FASB Statement No.143 , entities are required to record the fair market value of any legal liability related to the retirement of any of its assets in the period in which such liability is incurred. Our liabilities related to the retirement of our assets include our obligation to plugging wells upon termination of our operating activities, the dismantling of our geothermal 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, an entity either settles the obligation for its

Table of Contents


		recorded amount or incurs a gain or a loss with respect thereto, as applicable. We estimate the costs related to such liabilities and if such estimates are incorrect, then the capitalized costs and carrying amount of the related long-lived asset will change and as a result may affect our consolidated financial condition and results of operations.


	•	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.

We maintain a risk management strategy that incorporates the use of interest rate swaps and interest rate caps to minimize significant fluctuation in cash flows and/or earnings that are caused by interest rate volatility. Gain 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 interest on the related debt is paid. Gain or losses on contracts that are not designated to qualify as a cash flow hedge are included as a component of interest expense.


	•	Consolidation of Variable Interest Entities. In January 2003, the FASB issued FIN No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB 51 , as amended by FIN No. 46R in December 2003. Among other things, FIN No. 46R generally deferred the effective date of FIN No. 46 to the quarter ended March 31, 2004. The objectives of FIN No. 46R are to provide guidance on the identification of Variable Interest Entities, which we refer to as VIEs, for which control is achieved through means other than ownership of a majority of the voting interest of the entity, and how to determine which company (if any), as the primary beneficiary, should consolidate such VIE. A variable interest in a VIE, by definition, is an asset, liability, equity, contractual arrangement or other economic interest that absorbs the entity’s economic variability.

Effective as of March 31, 2004, we adopted FIN No. 46R. In connection with the adoption of FIN No. 46R, we concluded that Ormat Leyte Co., Ltd. (OLCL), in which we have an 80% ownership interest, should be deconsolidated. OLCL’s operating results were accounted for using the consolidation method of accounting for the three-month period ended March 31, 2004 and, effective April 1, 2004, our ownership interest in OLCL is accounted for using the equity method of accounting.


	•	Accounting for Income Taxes. As part of the process of preparing our consolidated financial statements in accordance with SFAS No. 109, Accounting for Income Taxes , we are required to estimate our income tax in each of the jurisdictions in which we operate. This process requires us to estimate our actual current tax exposure and make an assessment of temporary differences resulting from differing treatment of items for tax and accounting purposes. Such differences result in deferred tax assets and liabilities which are included in our consolidated balance sheet. We must then assess the likelihood that our net deferred tax assets will be recovered from future taxable income and, to the extent we believe that such recovery is not likely, we must establish a valuation allowance. To the extent we establish a valuation allowance or increase such allowance in a period, we must include an expense within the tax provision in our consolidated statement of operations. Management uses significant judgment in determining our deferred tax assets and liabilities and any valuation allowance recorded against our net deferred tax assets. In the event that we generate taxable income in a particular jurisdiction in which we operate and in which we have net operating loss carryforwards for which a deferred tax valuation allowance has been established, we may be required to adjust our valuation allowance. Realization of the deferred tax assets and investment tax credits is dependent on generating sufficient taxable income prior to expiration

Table of Contents


		of the loss carryforwards. Although realization is not assured, management believes it is more likely than not that the deferred tax asset as of December 31, 2006 will be realized. We account for investment tax credits and for production tax credits as a reduction to income tax in the year in which the credits arise.

New Accounting Pronouncements

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

Results of Operations

Our historical operating results in dollars and as a percentage of total revenues are presented below. The different periods described below may not be comparable, as a result of the effects on our historical operating results of our recent acquisitions and enhancements of acquired projects and construction of new projects.


	Year Ended December 31,
	2006				2005				2004
	(in thousands, except per share data)
Statements of Operations Historical Data:
Revenues:
Electricity Segment		$	195,483			$	177,369			$	158,831
Products Segment			73,454				60,623				60,399
			268,937				237,992				219,230
Cost of revenues:
Electricity Segment			124,356				103,615				89,742
Products Segment			51,215				45,236				46,336
			175,571				148,851				136,078
Gross margin:
Electricity Segment			71,127				73,754				69,089
Products Segment			22,239				15,387				14,063
			93,366				89,141				83,152
Operating expenses (income):
Research and development expenses			2,983				3,036				2,175
Selling and marketing expenses			10,361				7,876				7,769
General and administrative expenses			18,094				14,320				11,609
Gain on sale of geothermal resource rights			—				—				(845	)
Operating income			61,928				63,909				62,444
Other income (expense):
Interest income			6,560				4,308				1,316
Interest expense			(30,961	)			(55,317	)			(42,785	)
Foreign currency translation and transaction loss			(704	)			(439	)			(146	)
Other non-operating income			694				512				112
Income before income taxes, minority interest and equity in income of investees			37,517				12,973				20,941
Income tax provision			(6,403	)			(4,690	)			(6,609	)
Minority interest in earnings of subsidiaries			(813	)			—				(108	)
Equity in income of investees			4,146				6,894				3,567
Net income		$	34,447			$	15,177			$	17,791
Earnings per share:
Basic		$	1.00			$	0.48			$	0.72
Diluted		$	0.99			$	0.48			$	0.72
Weighted average number of shares used in computation of earnings per share:
Basic			34,593				31,563				24,806
Diluted			34,707				31,609				24,806

Table of Contents


	Year Ended December 31,
	2006			2005			2004
Statements of Operations Percentage Data:
Revenues:
Electricity Segment		72.7	%		74.5	%		72.4	%
Products Segment		27.3			25.5			27.6
		100.0			100.0			100.0
Cost of revenues:
Electricity Segment		63.6			58.4			56.5
Products Segment		69.7			74.6			76.7
		65.3			62.5			62.1
Gross margin:
Electricity Segment		36.4			41.6			43.5
Products Segment		30.3			25.4			23.3
		34.7			37.5			37.9
Operating expenses (income):
Research and development expenses		1.1			1.3			1.0
Selling and marketing expenses		3.9			3.3			3.5
General and administrative expenses		6.7			6.0			5.3
Gain on sale of geothermal resource rights		0.0			0.0			(0.4	)
Operating income		23.0			26.9			28.5
Other income (expense):
Interest income		2.4			1.8			0.6
Interest expense		(11.5	)		(23.2	)		(19.5	)
Foreign currency translation and transaction loss		(0.3	)		(0.2	)		(0.1	)
Other non-operating income		0.3			0.2			0.1
Income before income taxes, minority interest and equity in income of investees		14.0			5.5			9.6
Income tax provision		(2.4	)		(2.0	)		(3.0	)
Minority interest in earnings of subsidiaries		(0.3	)		0.0			(0.0	)
Equity in income of investees		1.5			2.9			1.6
Net income		12.8	%		6.4	%		8.1	%

Comparison of the Year Ended December 31, 2006 and the Year Ended December 31, 2005

Total Revenues

Total revenues for the year ended December 31, 2006 were $268.9 million, as compared with $238.0 million for the year ended December 31, 2005, which represented a 13.0% increase in total revenues. This increase is attributable both to our Electricity and Products Segments whose revenues increased by 10.2% and 21.2%, respectively, over the year ended December 31, 2005.

Electricity Segment

Revenues attributable to our Electricity Segment for the year ended December 31, 2006 were $195.5 million, as compared with $177.4 million for the year ended December 31, 2005, which represented a 10.2% increase in such revenues. This increase is primarily attributable to the following: (i) the consolidation of additional revenues in the amount of $10.3 million from the Zunil project, which was consolidated as of March 13, 2006; (ii) additional revenues of $5.9 million generated as a result of an increase in our generating capacity in the U.S. resulting in an increase in energy generation from 1,693,362 MWh in the year ended December 31, 2005 to 1,789,794 MWh in the year ended December 31 2006; and (iii) an increase of $1.3 million in lease income resulting from the Puna operating lease. We did not realize the aggregate generating capacity of our power plants in the year ended December 31, 2006 due to unexpected operational issues that we experienced in some of our plants, such as the Puna and Ormesa projects, and the delay in the commercial operation of the Desert Peak 2 plant.

Products Segment

Revenues attributable to our Products Segment for the year ended December 31, 2006 were $73.5 million, as compared with $60.6 million for the year ended December 31, 2005, which represented a 21.2% increase. This increase of $12.9 million in the year ended December 31, 2006 is principally attributable to increased sales of our geothermal and recovered energy generation products, which amounted to $68.8 million in the year ended December 31, 2006 as compared to $31.6 million, while sales of our remote power units decreased in the year ended December 31, 2006 following the completion of the large order received from the company developing the Sakhalin project in Russia which amounted to $18.9 million.

Total Cost of Revenues

Total cost of revenues for the year ended December 31, 2006 was $175.6 million, as compared with $148.9 million for the year ended December 31, 2005, which represented an 18.0% increase in total cost of revenues. The increase in cost of revenues is partially due to the increase in revenues and partially attributable to increased costs in our Electricity Segment during the year ended December 31, 2006, as discussed below. As a percentage of total revenues, our total cost of revenues for the years ended December 31, 2006 and 2005 were 65.3% and 62.5%, respectively. The increase in cost of revenues as a percentage of total revenues is principally attributable to the increased costs in our Electricity Segment during the year ended December 31, 2006, which was partially offset by an increase in the profitability of our Products Segment during the year ended December 31, 2006. Total cost of revenues for the year ended December 31, 2006 includes stock-based compensation related to stock options of $0.8 million.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2006 was $124.4 million, as compared with $103.6 million for the year ended December 31, 2005, which represented a 20.0% increase in cost of revenues for such segment. This increase is primarily due to the following: (i) a $4.1 million cost of repairing two wells that experienced mechanical problems in the Puna project (we have incurred approximately $2.0 million in

additional repair costs in the first quarter of 2007); (ii) an increase of $5.8 million in depreciation and royalties as a result of additional generating capacity; (iii) an increase of $2.7 million in cost of revenues attributable to the Zunil project which was consolidated as of March 13, 2006; (iv) an increase in lease expense of $2.2 million resulting from the Puna operating lease; and (v) additional insurance costs of $1.9 million due to higher insurance premiums and additional premiums as a result of coverage of our additional assets. The remaining $4.1 million of the increase in our cost of revenues is attributable primarily to increased labor and materials costs in existing plants. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2006 was 63.6% compared with 58.4% for the year ended December 31, 2005.

Products Segment

Total cost of revenues attributable to our Products Segment for the year ended December 31, 2006 was $51.2 million, as compared with $45.2 million for the year ended December 31, 2005, which represented a 13.2% increase in total cost of revenues related to such segment. Such $6.0 million increase in total cost of revenues during the year ended December 31, 2006 is attributable to the increase in our Products Segment revenues and a different product mix. As a percentage of total products revenues, our total cost of revenues attributable to our Products Segment for the year ended December 31, 2006 was 69.7% compared with 74.6% in the year ended December 31, 2005. Such 4.9% decrease was primarily attributable to the product mix.

Research and Development Expenses

Net research and development expenses for the year ended December 31, 2006 were $2.98 million, as compared with $3.04 million for the year ended December 31, 2005, which represented a 1.7% decrease in research and development expenses. Such decrease reflects fluctuations in the period in which actual expenses were incurred. Research and development expenses in the years ended December 31, 2006 and 2005 also include activity related to geothermal resource drillings. Grants received from the U.S. Department of Energy are offset against the related research and development expenses. Such grants amounted to $0.3 million and $1.3 million during the years ended December 31, 2006 and 2005, respectively.

Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2006 were $10.4 million, as compared with $7.9 million for the year ended December 31, 2005, which represented a 31.6% increase in selling and marketing expenses. The increase was due primarily to the increase in revenues in our Products Segment and an increase in personnel expenses and other administrative expenses as a result of the hiring of additional personnel to support our continued growth, and an increase in salaries. Selling and marketing expenses for the year ended December 31, 2006 constituted 3.9% of total revenues for such year, as compared with 3.3% for the year ended December 31, 2005. Such increase is principally attributable to an increase in personnel expenses and other administrative expenses, as described above, offset by the fixed cost nature of certain of our selling and marketing expenses against a larger total revenue base. Selling and marketing expenses for the year ended December 31, 2006 includes stock-based compensation related to stock options of $0.3 million.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2006 were $18.1 million, as compared with $14.3 million for the year ended December 31, 2005, which represented a 26.4% increase in general and administrative expenses. Such increase was primarily attributable to: (i) an increase in professional services fees, additional personnel expenses and other administrative expenses, all as a result of our initial implementation of internal controls and procedures required to comply with Section 404 of the Sarbanes-Oxley Act of 2002; (ii) an increase in personnel expenses and other administrative expenses as a result of the hiring of additional personnel to support our continued

growth and as a result of an increase in salaries; and (iii) an increase in insurance expenses of $0.6 million mainly related to political risk coverage of the Amatitlan project, which was under construction. General and administrative expenses for the year ended December 31, 2006 increased to 6.7% of total revenues for such period, from 6.0% for the year ended December 31, 2005. General and administrative expenses for the year ended December 31, 2006 includes stock-based compensation related to stock options of $0.6 million.

Interest Expense

Interest expense for the year ended December 31, 2006 was $31.0 million, as compared with $55.3 million for the year ended December 31, 2005, which represented a 44.0% decrease in such interest expense. The net decrease of $24.3 million was primarily due to a $16.6 million one-time charge relating to the early repayment of the Beal Bank loan, following the issuance of the OrCal Senior Secured Notes on December 8, 2005. Without the impact of the one-time charge, interest expense decreased by $7.7 million, which resulted from: (i) an increase of $4.6 million in interest capitalized to projects due to the higher volume of construction in this year compared with last year; (ii) a decrease of $2.3 million in interest expense to our parent; (iii) a decrease of $2.9 million in interest expense due to the refinancing of the Beal Bank loan with the OrCal Senior Secured Notes at a lower interest rate as described above; and (iv) a decrease of $0.6 million in interest expense in respect of the OFC Senior Secured Notes due to principal repayments. The decrease in interest expense was partially offset by an increase of $1.8 million in interest expense for the year ended December 31, 2006 attributable to the consolidation of interest expense from the Zunil project, which was consolidated as of March 13, 2006, and by a decrease of $0.6 million for the year ended December 31, 2006, in the fair value of interest rate caps, which as of December 8, 2005 are no longer qualified for hedge accounting due to the repayment of the Beal Bank loan.

Income Taxes

Income taxes for the year ended December 31, 2006 were $6.4 million, as compared with $4.7 million for the year ended December 31, 2005. The effective tax rates for the years ended December 31, 2006 and 2005 were 17.1% and 36.2%, respectively. Our effective tax rate decreased in the year ended December 31, 2006 compared with the year ended December 31, 2005 due to: (i) a production tax credit of $4.7 million in respect of our Burdette, Gould and Desert Peak 2 projects; (ii) the absence of income tax expense in respect of our Zunil project, due to our utilization of a tax credit in the amount of $1.1 million; (iii) a decrease of 3% in the tax rate in Israel commencing January 1, 2006, which decreased the tax provision by $0.5 million; and (iv) an Israeli Investment Law amendment and the resulting ruling from the Israeli Tax Authorities granted in April 2006 to Ormat Systems according to which Ormat Systems was subject to lower income tax rates effective as of January 1, 2004, which resulted in a tax benefit of $1.0 million.

Equity in Income of Investees

Our participation in the income generated from our investees for the year ended December 31, 2006 was $4.1 million, as compared with $6.9 million for the year ended December 31, 2005. Such decrease of $2.8 million was due to our 50% equity interest in the Mammoth project, whose revenues decreased because of lower generation as a result of temperatures higher than the average for the summer season and whose cost of revenues increased mainly as a result of unplanned major maintenance. In addition, the decrease in our equity in income of investees was attributable to the shutdown of the Zunil project in the first quarter of 2006, due to damage from a hurricane and the consolidation of Orzunil as of March 13, 2006, which decreased our equity income of investees by $0.7 million.

Net Income

Net income for the year ended December 31, 2006 was $34.4 million, as compared with $15.2 million for the year ended December 31, 2005, which represented an increase of 127.0% in our net income. Net income as a percentage of our total revenues for the year ended December 31, 2006

was 12.8%, as compared with 6.4% for the year ended December 31, 2005. Such increase in net income was principally attributable to: (i) a $16.6 million ($10.3 million after-tax) impact of the one-time charge from the repayment of the Beal Bank loan in the year ended December 31, 2005; (ii) a $4.2 million increase in gross margin primarily due to the increase in total revenues; and (iii) a decrease in our net interest expense of $10.0 million, offset by: (i) a decrease of $2.8 million in equity in income of investees; (ii) a $6.2 million increase in operating expenses; (iii) a $1.7 million increase in our income tax provision; and (iv) a $0.8 increase in minority interest in earnings of subsidiaries, due to the consolidation of the Zunil project. Net income for the year ended December 31, 2006 includes stock-based compensation related to stock options of $1.5 million.

Comparison of the Year Ended December 31, 2005 and the Year Ended December 31, 2004

Total Revenues

Total revenues for the year ended December 31, 2005 were $238.0 million, as compared with $219.2 million for the year ended December 31, 2004, which represented an 8.6% increase in total revenues. This increase is attributable primarily to the growth of our Electricity Segment, whose revenues in the year ended December 31, 2005 increased by 11.7% over the year ended December 31, 2004.

Electricity Segment


	Year Ended December 31,
	2005			2004
	(in millions)
Steamboat Project		$	17.6		$	15.4
Puna Project			36.2			15.5
Steamboat Hills Project			4.2			1.8
Other Projects			119.4			126.1
Total		$	177.4		$	158.8

Revenues attributable to our Electricity Segment for the year ended December 31, 2005 were $177.4 million, as compared with $158.8 million for the year ended December 31, 2004, which represented an 11.7% increase in such revenues. This increase is primarily attributable to the inclusion for a full year of the additional revenues being generated from the Steamboat 2/3 project, which we acquired on February 11, 2004, the Steamboat Hills project, which we acquired on May 20, 2004, and the Puna project, which we acquired on June 3, 2004. In addition, revenues from the Puna project in the year ended December 31, 2005 increased by $5.2 million due to higher energy rates, by $1.1 million due to increased generating capacity and by $1.4 million due to lease income resulting from the Puna operating lease. The decrease in revenues from Other Projects is primarily due to the deconsolidation of the Leyte project as of April 1, 2004, which represented $3.1 million of our revenues in the first quarter of 2004, a $3.1 million decrease due to lower availability of the well field at the Ormesa project and a $1.9 million decrease in the Heber project primarily due to our increased use of the power generated by the project for auxiliary purposes rather than purchasing this power from a third party, and a decrease in the ‘‘adder’’, an additional energy rate, paid under the Heber 2 power purchase agreement.

Products Segment

Revenues attributable to our Products Segment for the year ended December 31, 2005 were $60.6 million, as compared with $60.4 million for the year ended December 31, 2004, which represented a 0.4% increase in such revenues. The portion of our Products Segment revenues attributable to the supply of remote power units increased in the year ended December 31, 2005 due to a large order from the Sakhalin project, which amounted to $18.9 million. In the year ended December 31, 2004, a significant portion of our Products Segment revenues was attributable to two large geothermal projects in New Zealand, which amounted to $49.5 million. The revenues from those projects in the year ended December 31, 2005 amounted to $10.6 million.

Total Cost of Revenues

Total cost of revenues for the year ended December 31, 2005 was $148.9 million, as compared with $136.1 million for the year ended December 31, 2004, which represented a 9.4% increase in total cost of revenues. As a percentage of total revenues, our total cost of revenues for the years ended December 31, 2005 and December 31, 2004 were 62.5% and 62.1%, respectively. The increase is principally attributable to increased costs in our Electricity Segment during the year ended December 31, 2005.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2005 was $103.6 million, as compared with $89.7 million for the year ended December 31, 2004, which represented a 15.5% increase in cost of revenues for such segment. This increase is primarily due to the inclusion for a full year of the additional costs of revenues attributable to the Steamboat 1/1A and Steamboat 2/3 project (we acquired the Steamboat 2/3 project on February 11, 2004), the Steamboat Hills project (which we acquired on May 20, 2004) and the Puna project (which we acquired on June 3, 2004) for the year ended December 31, 2005 were $9.8 million, $3.0 million and $17.0 million, respectively, as compared with $7.7 million, $2.0 million and $6.6 million, respectively, for the year ended December 31, 2004. The remainder of the increase is mainly due to the increased costs in the amount of $3.0 million within the Ormesa project due to a significant increase in the geothermal field costs and maintenance costs of such project due to a higher-than-average rate of failure of production pumps and wells (including abandonment of one production well), which resulted in a lower availability of the well field. These costs included the replacement of a relatively large number of pumps and injection pipeline repairs. We also had increased costs in the amount of $0.8 million in the Steamboat project. The increase in total cost of revenues in our Electricity Segment was partially offset by the cancellation of accruals in the aggregate amount of $2.5 million due to the resolution of contingencies. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2005 (58.4%) was higher than the percentage for the year ended December 31, 2004 (56.5%). Such increase is due in part to a lease expense in the amount of $3.1 million in the Puna project from May 19, 2005 to December 31, 2005. The increase is also attributable to the deconsolidation of the Leyte project as of April 1, 2004, whose total cost of revenues as a percentage of the project’s revenues in 2004 was 46.3%, which is lower than the average cost of revenues for this segment.

Products Segment

Total cost of revenues attributable to our Products Segment for the year ended December 31, 2005 was $45.2 million, as compared with $46.3 million for the year ended December 31, 2004, which represented a 2.4% decrease in cost of revenues related to such segment. Such $1.1 million decrease in cost of revenues during the year ended December 31, 2005 resulted from a different product mix. As a percentage of total products revenues, our total cost of revenues attributable to our Products Segment for the year ended December 31, 2005 was 74.6% and for the year ended December 31, 2004 was 76.7%.

Research and Development Expenses

Net research and development expenses for the year ended December 31, 2005 were $3.0 million, as compared with $2.2 million for the year ended December 31, 2004, which represented a 39.6% increase in research and development expenses. Such increase reflects fluctuations in the period in which actual expenses were incurred and includes also an increase in activity related to geothermal resource drillings. Grants received from the U.S. Department of Energy are offset against the related research and development expenses. Such grants amounted to $1.3 million and $0.1 million during the years ended December 31, 2005 and 2004, respectively.

Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2005 were $7.9 million, as compared with $7.8 million for the year ended December 31, 2004. Selling and marketing expenses for

the year ended December 31, 2005 constituted 3.3% of total revenues for such year, as compared with 3.5% for the year ended December 31, 2004. Such decrease is principally attributable to the fixed cost nature of certain of our selling and marketing expenses against a larger total revenue base.

General and Administrative Expenses

General and administrative exenses for the year ended December 31, 2005 were $14.3 million, as compared with $11.6 million for the year ended December 31, 2004, which represented a 23.4% increase in general and administrative expenses. Such increase was principally attributable to an increase in professional services fees, additional personnel expenses and other administrative expenses, all as a result of being a public company whose shares are traded on the New York Stock Exchange. General and administrative expenses for the year ended December 31, 2005 constituted 6.0% of total revenues for such period, as compared with 5.3% for the year ended December 31, 2004. In addition, the general and administrative expenses for the year ended December 31, 2004 did not fully reflect the increase in such expenses that was required as a result of the increased activity that occurred in connection with the acquisitions made in 2004.

Interest Expense

Interest expense for the year ended December 31, 2005 was $55.3 million, as compared with $42.8 million for the year ended December 31, 2004, which represented a 29.3% increase in such interest expense. The net increase of $12.5 million was primarily due to a $16.6 million one-time charge relating to the early repayment of the Beal Bank loan, which followed the issuance of the OrCal Senior Secured Notes. The charge is comprised of an $11.5 million prepayment premium, a $4.2 million write-off of deferred financing costs and a $0.9 million loss from a hedge transaction previously included in other comprehensive loss. Without the impact of the one-time charge, interest expense decreased by $4.1 million, which resulted from (i) $3.5 million in interest capitalized to projects due to a higher volume of construction as compared with $0.6 million last year, (ii) a decrease in interest expenses of $2.2 million as a result of the repayment of the Ormesa loan on December 31, 2004, (iii) the payment of an interest expense of $1.6 million for the year ended December 31, 2004 related to the decrease in the fair value of the interest rate caps in respect of the Beal Bank financing; beginning in October 2004 the caps qualified for hedge accounting under SFAS No. 133, and as such we have recorded the decrease in the value of the caps in respect of such transactions in other comprehensive income. As a result of the repayment of the Beal Bank loan on December 8, 2005, these caps are no longer qualified for hedge accounting and for the period from December 8, 2005 to December 31, 2005, $0.3 million were included in interest expense related to the decrease in the fair value for such period. In addition, the decrease in the fair value from October 1, 2004 to December 8, 2005 in the amount of $0.9 million was included in the prepayment charge as described above, and (iv) the elimination of interest expenses of the loan from Export-Import Bank used to finance the Leyte project in the amount of $0.2 million as a result of the deconsolidation of the Leyte project in April 1, 2004 (as a result of the application of FIN No. 46R). Such decreases were offset by: a $1.9 million increase in interest expense in respect of the $190.0 million of the OFC Senior Secured Notes, a $0.9 million increase in interest payments to our parent, and a $0.8 million increase in the applicable LIBOR rate for the Beal Bank financing.

Income Taxes

Income taxes for the year ended December 31, 2005 were $4.7 million, as compared with $6.6 million for the year ended December 31, 2004. The effective tax rates for the years ended December 31, 2005 and 2004 were 36.2% and 31.6%, respectively. Our effective tax rate increased in the year ended December 31, 2005 compared with the year ended December 31, 2004 primarily due to utilization of carry-forward tax losses in Israel during the first half of 2004, for which a full valuation allowance has been recorded against deferred tax assets. No investment tax credit or production tax credits were claimed in the years ended December 31, 2005 and 2004.

During the year ended December 31, 2005, Ormat Momotombo Power Company paid the total amount of approximately $1,700 in tax penalties, due mainly to the late filings of tax withholding reports.

Equity in Income of Investees

Our participation in the income generated from our investees for the year ended December 31, 2005 was $6.9 million, as compared with $3.6 million for the year ended December 31, 2004, which represented a 93.3% increase. Such increase was principally attributable to the income generated in connection with our 80% equity interest in the Leyte project, which was deconsolidated as of April 1, 2004 (as a result of the application of FIN No. 46R), which accounted for $4.9 million, and our collection of an insurance claim, that had not been insured until collected, related to that project in the second quarter of 2005. In the third quarter of 2004, the Leyte Project had a net loss as a result of equipment damage, which was recovered by insurance payments in the fourth quarter of 2004 and the second quarter of 2005.

Net Income

Net income for the year ended December 31, 2005 was $15.2 million, as compared with $17.8 million for the year ended December 31, 2004. Net income as a percentage of our total revenues for the year ended December 31, 2005 was 6.4%, as compared with 8.1% for the year ended December 31, 2004. The $2.6 million decrease in net income and the decrease in net income as a percentage of our total revenues were due to a $10.3 million after-tax impact of the one-time charge from the repayment of the Beal Bank loan. The impact of the prepayment charge was partially offset by an increase in net income principally attributable to: (i) a $6.0 million increase in gross margin, (ii) a decrease in our net interest expense of $7.1 million, (iii) a $1.9 million decrease in our income tax provision, and (iv) an increase of $3.3 million in equity in income of investees, offset by a $4.5 million increase in operating expenses. Net income excluding the after-tax impact of the prepayment charge was $25.5 million, an increase of $7.7 million or 43.2% compared with the net income for the year ended December 31, 2004.

Stock-based Compensation

Effective January 1, 2006, we adopted SFAS No. 123(R), Share-Based Payments , (SFAS No. 123R), which establishes the accounting for employee stock-based awards. Under the provisions of SFAS No. 123R, stock-based compensation 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). We adopted SFAS No. 123R using the modified prospective method. Under this method, prior periods are not restated and the amount of compensation cost recognized includes (i) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123, Accounting for Stock-Based Compensation , and (ii) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123R. Prior to January 1, 2006, we accounted for stock-based compensation in accordance with the provisions of Accounting Principles Board Opinion No. 25 (APB No. 25), Accounting for Stock Issued to Employees , and related interpretations. Under APB No. 25, compensation cost was recognized based on the difference, if any, on the date of grant between the fair value of our common stock and the amount an employee must pay to acquire the stock.

During the year ended December 31, 2006, we recognized net stock-based compensation expenses related to stock options of $1.5 million. As of December 31, 2006, the unrecorded deferred stock-based compensation balance related to stock options was $3.7 million and will be recognized over an estimated weighted average amortization period of 3.4 years.

Liquidity and Capital Resources

To date, our principal sources of liquidity have been derived from cash from operations, proceeds from parent company loans, third party debt in the form of borrowing under credit facilities, issuance by Ormat Funding and OrCal Geothermal of their Senior Secured Notes, project financing (including lease) and the issuance of our common stock in public offerings. We have utilized this cash to fund

our acquisitions, develop and construct power generation plants and meet our other cash and liquidity needs. Our management believes that the outstanding cash, cash equivalents, marketable securities and cash generated from our operations will address our liquidity and other investment requirements. In addition, our shelf registration statement on Form S-3, which was declared effective on January 31, 2006, provides us with the ability to raise additional capital through the issuance of securities pursuant to the terms and conditions of the shelf registration. As described below, since the capital note in the amount of $50.7 million with our parent is payable upon demand at any time after November 30, 2007, it is presented in our balance sheet as of December 31, 2006 in current liabilities.

Loan Agreements with our Parent

In 2003, we entered into a loan agreement with Ormat Industries Ltd. (our parent company), which was further amended on September 20, 2004. Pursuant to this loan agreement, Ormat Industries agreed to make a loan to us in one or more advances not exceeding a total aggregate amount of $150.0 million. The proceeds of the loan are to be used to fund our general corporate activities and investments. We are required to repay the loan and accrued interest in full and in accordance with an agreed-upon repayment schedule and in any event on or prior to June 5, 2010. Interest on the loan is calculated on the balance from the date of the receipt of each advance until the date of payment thereof at a rate per annum equal to Ormat Industries’ average effective cost of funds plus 0.3% in dollars, which represented a rate of 7.5% for the advances made during 2003. All computations of interest shall be made by Ormat Industries on the basis of a year consisting of 360 days. As of December 31, 2006, the outstanding balance of the loan was approximately $89.5 million compared to $121.1 million as of December 31, 2005.

In addition to the above loan, pursuant to the terms of a capital note, as amended on September 20, 2004, Ormat Industries converted outstanding balances owed by us to Ormat Industries into a subordinated non-interest bearing loan in an amount equal to New Israeli Shekels (NIS) 240.0 million. At any time after November 30, 2007 upon demand by Ormat Industries, we will be required to repay the loan in full. The final maturity of the loan is December 30, 2009. In accordance with the terms of such note, we will not be required to repay any amount in excess of $50.7 million (using the exchange rate existing on the date of such note). As of December 31, 2006 and 2005 the ceiling of $50.7 million is effective. Since the note is payable upon demand at any time after November 30, 2007 it is presented in our balance sheet as of December 31, 2006 in current liabilities.

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. The second category consists of debt incurred by us or our subsidiaries for general corporate purposes.

OrCal Geothermal Senior Secured Notes — Non-Recourse

On December 8, 2005, OrCal Geothermal Inc (OrCal), one of our subsidiaries, 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, 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, 2006, we were in compliance with the covenants under the OrCal Senior Secured Notes.

The proceeds from this issuance were used to prepay in full OrCal’s outstanding loan with Beal Bank and to pay for transaction costs. As a result of the prepayment of the Beal Bank loan, we

recorded in the fourth quarter of 2005 a net charge of approximately $10.3 million, net of related taxes of approximately $6.3 million. As of December 31, 2006, there were $160.7 million of OrCal Senior Secured Notes outstanding.

Ormat Funding Senior Secured Notes — Non-Recourse

On February 13, 2004, Ormat Funding Corp. (OFC), one of our subsidiaries, issued $190.0 million, 8¼% 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, 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 that commenced on June 30, 2004. The OFC Senior Secured Notes are collateralized by substantially all of the assets of Ormat Funding 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. On June 30 and December 31, 2006, OFC did not meet the ‘‘debt service coverage ratio’’ and therefore it was restricted from payment of dividends until it meets such ratio. As of December 31, 2006, there were $178.7 million of OFC Senior Secured Notes outstanding.

We have not yet granted a security interest over the new unit of the Desert Peak 2 project to the OFC Senior Secured Noteholders which is required under the indenture for the OFC Senior Secured Notes. We are evaluating an alternative approach to replacing the Desert Peak 1 plant with one of the new units of the Desert Peak 2 project. Implementing such an alternative would require the consent of the OFC Senior Secured Noteholders in order to ensure continued compliance with the covenants of the indenture governing the OFC Senior Secured Notes. We expect to launch a consent solicitation in order to amend and/or waive certain provisions of the indenture to obtain such consent from the OFC Senior Secured Noteholders. Any such solicitation will be made by means of and subject to appropriate documentation and only to the OFC Senior Secured Noteholders.

A registration statement on Form S-4 relating to the OFC Senior Secured Notes was filed with and declared effective by the SEC on February 9, 2005. On March 16, 2005, we exchanged these unregistered notes for senior secured notes with substantially identical terms that have been registered under the Securities Act of 1933, as amended.

On April 26, 2006, OFC successfully consummated a consent solicitation relating to the OFC Senior Secured Notes that was launched on April 17, 2006. On that same date, OFC executed a supplement to the Indenture governing the OFC Senior Secured Notes to amend and/or waive certain provisions in the indenture dealing with public reporting and information requirements of OFC. On May 1, 2006, OFC filed with the SEC a Form 15 notification of the suspension of its obligation to file reports with the SEC under the Securities Act of 1934.

Senior Loans from International Finance Corporation (IFC) and Commonwealth Development Corporation (CDC) — Non-Recourse

Orzunil, a wholly owned subsidiary which was consolidated as of March 13, 2006, has senior loan agreements with IFC and CDC, which were minority shareholders of Orzunil (see ‘‘Recent Developments’’ regarding our acquisition of the minority interest in Orzunil). The first loan from IFC, of which $7.0 million was outstanding as of December 31, 2006, has a fixed annual interest rate of 11.775%, and matures on November 15, 2011. The second loan from IFC, of which $3.9 million was outstanding as of December 31, 2006, has a fixed annual interest rate of 11.730%, and matures on May 15, 2008. The loan from CDC, of which $8.5 million was outstanding as of December 31, 2006, has a fixed annual interest rate of 10.3%, and matures on August 15, 2010. There are various restrictive covenants under the Senior Loans, which include limitations on Orzunil’s ability to make distributions to its shareholders.

Due to hurricane activity, access roads and piping from the wells to the power plant in the Zunil Project were damaged and as a result, the Project was not in operation from October 14, 2005 to

March 10, 2006. As a result, Orzunil did not meet the historical ‘‘debt service coverage ratio’’ required and therefore distributions from the Project are restricted. Currently, Orzunil is in compliance with the required debt service coverage ratio and with all other covenants.

Other Limited and Non-Recourse Debt

The Bank Hapoalim project finance debt, of which $11.3 million was outstanding as of December 31, 2006, bearing an interest rate of 3-month LIBOR plus 2.375% per annum on tranche one of the loan and 3-month LIBOR plus 3.0% per annum on tranche two of the loan, and the Export-Import Bank of the United States project finance debt, of which $3.8 million was outstanding as of December 31, 2006, bearing an interest rate of 6.54% per annum, were entered into by our relevant subsidiaries to finance the Momotombo project and the Leyte project (which was deconsolidated as of April 1, 2004), respectively.

Our management believes that we are currently in compliance with our covenants with respect to our third-party debt, except as described above regarding the OFC Senior Secured Notes and the Orzunil Senior Loans.

New Financing of our Projects

Financing of the Amatitlan Project

Currently, we intend to refinance our equity investment in the construction cost of the Amatitlan project during the third quarter of 2007. In connection with such refinancing, we signed a mandate letter with a local bank in Guatemala containing proposed terms for a construction loan with a term of up to two years and a 10-year term loan in the total amount of approximately $41.0 million.

Financing of Phase II of Olkaria III Project

We have engaged a financial institution and received an indicative proposal to arrange long-term financing for the Olkaria III project. We expect negotiations and preparation of loan documentation to follow shortly.

Full-Recourse Debt

Our full-recourse third party debt includes an $8 million medium term loan from Bank Hapoalim, of which $2.0 million was outstanding as of December 31, 2006, bearing an interest rate of 12-month LIBOR plus 1.7% per annum.

In connection with our acquisition through Ormat Systems Ltd. of the power generation business from our parent, we entered into certain agreements with various banks, of which only those with each of Bank Hapoalim, Bank Leumi and Mizrahi Tefahot Bank remain. Under these agreements, in exchange for such banks’ release of our parent’s guarantee and a release of their security interest over the assets of our subsidiary, Ormat Systems, we and Ormat Systems have agreed to certain negative covenants, including, but not limited to, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of our assets. In some cases, we and Ormat Systems have agreed to maintain certain financial ratios such as a debt service coverage ratio and a debt to equity ratio. We do not expect that these covenants or ratios, which apply to us on a consolidated basis, will materially limit our ability to execute our future business plans or our 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.

We do not expect that any third party debt that we, or any of our subsidiaries, will incur in the future will be guaranteed by our parent.

Most of the loan agreements to which we or our subsidiaries are a party contain cross-default provisions with respect to other material indebtedness owed by us to any third party.

On February 15, 2006, our subsidiary, Ormat Nevada, entered into a $25.0 million credit agreement with Union Bank of California (UBOC). 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. UBOC 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 the floating rate based on the Eurodollar plus a margin. There are various restrictive covenants under the credit agreement, which include maintaining certain levels of tangible net worth, leverage ratio, minimum coverage ratio, and a distribution coverage ratio. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios.

As of December 31, 2006, three letters of credit, with an aggregate stated amount of $21.9 million, have been issued and are outstanding under this credit agreement with UBOC.

Letters of Credit and Off-balance Sheet Arrangements

As described above under ‘‘Full Recourse Debt’’, on February 15, 2006, our subsidiary Ormat Nevada, entered into a credit agreement with Union Bank of California.

On June 30, 2004, our subsidiary, Ormat Nevada, entered into a Letter of Credit Agreement with Hudson United Bank, pursuant to which Hudson United Bank agreed to issue one or more letters of credit in an aggregate face amount of up to $15.0 million. Under this Letter of Credit Agreement in the event that the bank is required to pay on a letter of credit drawn by the beneficiary thereof, such letter of credit converts to a loan, bearing interest at one-month LIBOR plus 4.0%, and matures on the next expiration date of the Letter of Credit Agreement. There are various restrictive covenants under the Letter of Credit Agreement, which include maintaining certain levels of tangible net worth, leverage ratio, and minimum coverage ratio. Some of our customers require our project subsidiaries to post letters of credit in order to guarantee their respective performance under relevant contracts. We are also required to post letters of credit to secure our obligations under various leases and licenses and may, from time to time, decide to post letters of credit in lieu of cash deposits in reserve accounts under certain financing arrangements. In addition, our subsidiary, Ormat Systems, is required from time to time to post performance letters of credit in favor of our customers with respect to orders of products. As of December 31, 2006 and 2005, no letters of credit were outstanding under the Letter of Credit Agreement.

Bank Leumi and Bank Hapoalim have issued such performance letters of credit in favor of our customers from time to time. Initially, our parent, Ormat Industries, was the obligor in respect of any reimbursement obligation on such letters of credit and we paid our parent a guarantee fee and were responsible to reimburse our parent for any draw under these letters of credit. In connection with the acquisition transaction of the power generation business by Ormat Systems from our parent, we have assumed such letters of credit and are now the direct obligor of Bank Leumi and Bank Hapoalim on such letters of credit. As of December 31, 2006, Bank Leumi and Bank Hapoalim have agreed to make available to us letters of credit totaling $25.6 million and $7.9 million, respectively. As of such date, Bank Leumi and Bank Hapoalim have issued letters of credit in the amount of $10.7 million and $6.6 million, respectively.

As of the date hereof, we have not had a draw presented against any letter of credit issued or provided on our behalf.

Puna Project Lease Transactions

On May 19, 2005, our subsidiary in Hawaii, Puna Geothermal Ventures (PGV), entered into a transaction involving the Puna geothermal power plant located on the Big Island of Hawaii. The transaction was concluded with financing parties by means of a leveraged lease transaction. A secondary stage of the lease transaction relating to two new geothermal wells that PGV drilled in the second half of 2005 (for production and injection) was completed on December 30, 2005. Pursuant to a 31-year head lease, PGV leased its geothermal power plant to the abovementioned financing parties in return for a deferred lease income in the amount of $83.0 million. Transaction costs amounted to $4.3 million. The proceeds from the transactions are being used for future capital expenditures and for general corporate purposes.

Dividend

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

Date Declared

Dividend Amount
per Share

Record Date

Payment Date

March 22, 2005

0.03

April 4, 2005

April 18, 2005

May 10, 2005

0.03

May 23, 2005

June 6, 2005

August 11, 2005

0.03

August 22, 2005

September 1, 2005

November 9, 2005

0.03

November 29, 2005

December 6, 2005

March 7, 2006

0.03

March 28, 2006

April 4, 2006

May 9, 2006

0.04

May 23, 2006

May 30, 2006

August 6, 2006

0.04

August 23, 2006

August 30, 2006

November 7, 2006

0.04

November 30, 2006

December 13, 2006

February 27, 2007

0.07

March 21, 2007

March 29, 2007

Historical Cash Flows

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


	Year Ended December 31,
	2006				2005				2004
	(dollars in thousands)
Net cash provided by operating activities		$	73,035			$	134,938			$	63,458
Net cash used in investing activities			(249,147	)			(83,408	)			(310,583	)
Net cash provided by (used in) financing activities			169,390				(61,304	)			275,002
Net increase (decrease) in cash and cash equivalents			(6,722	)			(9,774	)			27,877

For the Year Ended December 31, 2006

Net cash provided by operating activities for the year ended December 31, 2006 was $73.0 million, as compared with net cash provided by operating activities of $134.9 million for the year ended December 31, 2005. Such net decrease of $61.9 million resulted primarily from: (i) the increase in net income from $15.2 million to $34.4 million as a result of additional revenues being generated from the increase of our generating capacity in the United States and from the Zunil project which was consolidated as of March 13, 2006; (ii) the prepaid lease payment of $83.0 million in the year ended December 31, 2005 pursuant to the leverage lease transaction of the Puna project (less $3.3 million deferred costs related to such lease transaction); and (iii) an increase of $12.1 million in accounts payable and accrued expenses for the year ended December 31, 2006 as compared with an increase of $7.2 million for the year ended December 31, 2005 mainly due to interest accrued on the OFC and OrCal Senior Secured Notes (which was paid on January 2, 2007), offset by a decrease in trade payables as a result of the timing of payments to suppliers and service providers.

Net cash used in investing activities for the year ended December 31, 2006 was $249.1 million, as compared with $83.4 million used in investing activities for the year ended December 31, 2005. The principal factors that affected our cash flow used in investing activities during the year ended December 31, 2006 were: (i) capital expenditures of $159.5 million utilized primarily for our power facilities under construction; (ii) $22.8 million used in the acquisition of an additional 79% of the Zunil project in Guatemala; and (iii) a net increase of $52.7 million in our investment of excess cash in marketable securities.

Net cash provided by financing activities for the year ended December 31, 2006 was $169.4 million, as compared with $61.3 million used in financing activities for the year ended December 31, 2005. The principal factors that affected the cash flow used in financing activities during the year ended December 31, 2006 were the receipt of proceeds from the follow-on offering of $135.1 million and the $92.4 million net proceeds from our sale of shares in a block trade, offset by: (i) the repayment of short-term and long-term debt in the amount of $20.7 million, (ii) the repayment of debt to our parent in the amount of $31.6 million; and (iii) the payment of a dividend to our shareholders in the amount of $5.2 million.

For the Year Ended December 31, 2005

Net cash provided by operating activities for the year ended December 31, 2005 was $134.9 million, as compared with net cash provided by operating activities of $63.5 million for the year ended December 31, 2004. Such net increase of $71.5 million resulted primarily from a prepaid lease payment of $83.0 million pursuant to the leverage lease transaction of Puna (less $3.3 million transaction costs related to such lease transaction) offset mainly by a decrease of $2.6 million in net income due to the prepayment charge relating to the Beal Bank Loan, net of an increase in the operating activities as a result of the inclusion for a full year of the additional revenues being generated from the Steamboat 2/3 project, which we acquired on February 11, 2004, the Steamboat Hills project, which we acquired on May 20, 2004, and the Puna project, which we acquired on June 3, 2004.

Net cash used in investing activities for the year ended December 31, 2005 was $83.4 million, as compared with $310.6 million used in investing activities for the year ended December 31, 2004. The principal factor that affected our cash flow used in investing activities during the year ended December 31, 2005 was capital expenditures of $116.7 million primarily for our power facilities under construction. Such cash used in investing activities was offset by a decrease of $45.6 million in marketable securities of which $13.7 million was allocated to restricted cash.

Net cash used in financing activities for the year ended December 31, 2005 was $61.3 million, as compared with $275.0 million provided by financing activities for the year ended December 31, 2004. The principal factors that affected the cash flow used in financing activities during the year ended December 31, 2005 were the repayment of short-term and long-term debt in the amount of $184.0 million (including the Beal Bank loan), repayment of debt to our parent in the amount of $40.2 million, and the payment of a dividend to our shareholders in the amount of $6.3 million. This decrease was partially offset by the $165.0 million in proceeds (less $3.9 million in debt issuance costs) from the issuance of OrCal Senior Secured Notes, which were used to repay the Beal Bank loan.

Capital Expenditures

Our capital expenditures primarily relate to two principal components: the enhancement of our existing power plants and the construction and development of new power plants. In addition, we have budgeted approximately $16.0 million for the next two years for investment in buildings, machinery and equipment, including drilling equipment.

To the extent not otherwise described below, 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 currently do not contemplate obtaining any new loans from our parent company.

Amatitlan Project. We completed the construction of the Amatitlan project, and expect to declare commercial operation in the first half of 2007.

Ormesa Project. We completed the drilling of additional wells at the Ormesa project. We are in the process of adding additional OEC units, and increasing the output of the project by an estimated 10 MW. We estimate that such enhancements will be completed by the end of the first quarter of 2007. We are currently in negotiations with Southern California Edison for the sale of this additional estimated 10 MW.

Galena 2 Project (formerly Desert Peak 3 Project) . We are in the final construction stage of the Galena 2 power plant in the Steamboat complex, which will supply electricity under the Galena 2 power purchase agreement. We estimate that the construction of the Galena 2 project will be completed in the first half of 2007.

Phase II of Olkaria III Project. In connection with Phase II of the Olkaria III project, we completed the drilling of the wells and have recently released the construction of the 35 MW power plant.

OrSumas Project. This recovered energy 5 MW project was scheduled to be completed in the last quarter of 2007 or the first quarter of 2008. The environmental issues identified in this project and described elsewhere in this report may delay or terminate its completion.

Steamboat Hills Project. We plan to add 5 MW to the Steamboat Hills project through the construction of OEC Units. Construction has been completed and the project is in its start up phase.

Puna Project. An enhancement program for the Puna project is currently planned and is intended to increase the output of the project by an estimated 8 MW through the construction of OEC Units. We expect that such enhancement program will be completed in 2008 and are currently negotiating the power purchase agreement for that addition.

Heber SouthProject (formerly Imperial Valley) . We commenced construction of the Heber South project, a 10 MW power plant, which will be located in the Heber known geothermal resource area. The construction activity is expected to include the drilling of production and injection wells and the construction of an OEC unit. We expect the construction to be completed by the end of 2007 or the beginning of 2008.

Galena 3 Project. We are currently constructing the Galena 3 project, which will deliver 17 MW of power generation under a 20-year power purchase agreement with Sierra Pacific Power Company. We expect the construction to be completed by the end of 2007 or the beginning of 2008.

Brawley Phase I Project. We are currently constructing the Brawley Phase I project, which will deliver approximately 50 MW of power generation. We expect the construction to be completed by the end of 2008.

We have budgeted approximately $520 million through the end of 2008 for the above-described projects and have invested $150 million of such budget as of December 31, 2006.

In addition to the above projects, our operating projects have capital and expenditures budgets of approximately $16.7 million and we also plan to start other construction and enhancement of additional projects, including exploration work, for a total investment amount of approximately $17.0 million.

Other than the enhancements and new projects described above, and new projects that we may develop under new bids, we do not anticipate any other material capital expenditures in the near term for any of our operating projects, other than ordinary maintenance requirements and major maintenance, which we typically fund with internally generated cash.

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 power purchase

agreements 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 power purchase agreements of the Heber 1 and 2 projects, the Ormesa project and the Mammoth project will be determined by reference to the relevant power purchaser’s short run avoided costs. The Puna project is currently benefiting from energy prices which are higher than the floor under the Puna power purchase agreement, as a result of the high fuel costs that impact Hawaii Electric Light Company’s avoided costs. In addition, under certain of the power purchase agreements for our projects in Nevada, the price that Sierra Pacific Power Company pays for energy and capacity is based upon California-Oregon border power market pricing.

As of December 31, 2006, 97.4% of our consolidated long-term debt (including amounts owed to our parent) was in the form of fixed rate securities and therefore not subject to interest rate volatility risk. As of such date, 2.6% 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, 2006, $13.3 million of our debt remained subject to some floating rate risk. As such, our exposure to changes in interest rates with respect to our long-term obligations is immaterial.

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 new Israeli shekel (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. All of our power purchase agreements 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.

We currently maintain our surplus cash in short-term, interest-bearing bank deposits and auction rate securities, which we refer to as PARS (deposits of entities with a minimum investment grade rating of AA by Standard & Poor’s Ratings Services).

Effects of Inflation

We do not expect that the low inflation environment of recent years in most of the countries in which we operate will continue. 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 power purchase agreements that could be triggered upon such occurrences. Energy payments pursuant to the power purchase agreements for the Mammoth project (after April 2012), Ormesa project (after April 2012), Heber 1 and 2 projects (after April 2012) and Steamboat 1/1A project will change because of our power purchasers’ underlying short run avoided costs. To the extent that inflation causes an increase in those short run avoided costs, higher energy payments could have an offsetting impact to any inflation-driven increase in our expenses. Similarly, the energy payments pursuant to the power purchase agreements for the Brady project, Steamboat 2/3 project, the Steamboat Hills project and the Burdette project increase every year through the end of the relevant terms of such agreements, though such increases are not directly linked to the CPI. Lease

payments are generally fixed, while royalty payments are generally determined as a percentage of revenues and therefore are not significantly impacted by inflation.

Overall, we believe that the impact of inflation on our business will not be significant.

Contractual Obligations and Commercial Commitments

The following table sets forth our material contractual obligations as of December 31, 2006, excluding interest (in thousands):


	Payment of Principal Due By Period
	Remaining Total			2007			2008			2009			2010			2011			Thereafter
Long-Term non-recourse and limited recourse debt		$	30,639		$	8,482		$	7,667		$	6,676		$	6,101		$	1,713		$	—
Long-Term recourse debt			2,000			1,000			1,000			—			—			—			—
Senior secured notes due 2020			339,370			40,054			25,476			20,183			20,334			21,110			212,213
Ormat Industries notes payable			140,153			82,312			31,641			16,600			9,600			—			—
Total		$	512,162		$	131,848		$	65,784		$	43,459		$	36,035		$	22,823		$	212,213

The following table sets forth our interest payments payable in connection with our contractual obligations as of December 31, 2006 (in thousands):


	Payment of Interest Due By Period
	Remaining Total			2007			2008			2009			2010			2011			Thereafter
Long-Term non-recourse and limited recourse debt		$	6,575		$	2,778		$	1,905		$	1,215		$	548		$	129		$	—
Long-Term recourse debt			216			144			72			—			—			—			—
Senior secured notes due 2020			187,871			35,730			21,554			19,924			18,483			16,997			75,183
Ormat Industries notes payable			10,977			5,982			3,549			716			730			—			—
Total		$	205,639		$	44,634		$	27,080		$	21,855		$	19,761		$	17,126		$	75,183

Interest on the OFC Senior Secured Notes due in 2020 is fixed at a rate of 8.25%. Interest on the OrCal Senior Secured Notes due in 2020 is fixed at a rate of 6.21%. Interest on the Orzunil Senior Loans due in 2008, 2010 and 2011 is fixed at rates of 11.730%, 10.300% and 11.775%, respectively. Interest on Ormat Industries notes payable in the amount of $89.5 million is fixed at the rate of 7.50%, while a capital note in the amount of NIS 240 million ($50.7 million, using the exchange rate existing on the date of such note) is interest free. 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.

The following table sets forth our future minimum lease payments under the Puna project’s lease, as of December 31, 2006 (in thousands):


	Future Minimum Lease Payments Due By Period
	Remaining Total			2007			2008			2009			2010			2011			Thereafter
Operating lease payments		$	113,082		$	9,742		$	7,573		$	8,013		$	7,567		$	8,061		$	72,126

The following table sets forth our future payment of benefits to our employees in Israel upon their reaching normal retirement age, as of December 31, 2006 (in thousands):


	Benefit Payments Upon Retirement Due By Period
	Remaining Total			2007			2008			2009			2010			2011			Thereafter
Benefits payments upon retirement		$	7,126		$	794		$	624		$	702		$	42		$	668		$	4,296

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.

Concentration of Credit Risk

Our credit risk is currently concentrated with a limited number of major customers: Sierra Pacific Power Company, Southern California Edison and Hawaii Electric Light Company. If any of these electric utilities fails to make payments under its power purchase agreements with us, such failure would have a material adverse impact on our financial condition.

Southern California Edison accounted for 30.0%, 36.1% and 41.4% of our total revenues for the three years ended December 31, 2006, 2005 and 2004, respectively. Southern California Edison is also the power purchaser and revenue source for our Mammoth project, which we account for separately under the equity method of accounting.

Sierra Pacific Power Company accounted for 12.8%, 14.1% and 12.9% of our total revenues for the three years ended December 31, 2006, 2005 and 2004, respectively.

Hawaii Electric Light Company accounted for 15.1%, 15.2% and 7.1% of our total revenues for the years ended December 31, 2006, 2005 and 2004, respectively.

Government Grants and Tax Benefits

The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies. We are permitted to claim approximately 10% of the cost of each new geothermal power plant in the United States as an investment tax credit against our federal income taxes. Alternatively, we are permitted to claim a ‘‘production tax credit,’’ which in 2006 was 1.9 cents per kWh and which is adjusted annually for inflation. The production tax credit may be claimed on the electricity output of new geothermal power plants put into service by December 31, 2008. Credit may be claimed for ten years on the output from any new geothermal power plants put into service prior to December 31, 2008. The owner of the project must choose between the production tax credit and the 10% 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 we claim the production tax credit or the investment credit, 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 investment credit, our ‘‘tax base’’ in the plant that we can recover through depreciation must be reduced by half of the tax credit; if we claim a production tax credit; there is no reduction in the tax basis for depreciation.

Our subsidiary, Ormat Systems, received from Israel’s Investment Center ‘‘Approved Enterprise’’ status under Israel’s Law for Encouragement of Capital Investments, 1959 (the Investment Law), with respect to two of its investment programs. One such approval was received in 1996 and the other was received in May 2004. In respect of the approval from 1996, Ormat Systems has utilized all the tax benefits it was entitled to. Recently, due to a broad legislative amendment in the Investment Law, Ormat Systems replaced the certificate approval received in May 2004 from Israel’s Investment Center with a ruling from the Israeli Tax Authorities. The ruling was obtained in April 2006. By replacing the approval with a ruling, Ormat Systems maximized the tax benefits it is entitled to under the

Investment Law. As an Approved Enterprise and according to the ruling, Ormat Systems is exempt from Israeli income taxes with respect to income derived from the approved investment for the years 2004 and 2005 and thereafter such income is subject to reduced Israeli income tax rates of 25% for an additional five years. These benefits are subject to certain conditions set forth in the ruling, including among other things, that all transactions between Ormat Systems and our affiliates are at arms length, and that the management and control of Ormat Systems will be from Israel during the whole period of the tax benefits. A change in control should be reported to the Israeli Tax Authorities in order to maintain the tax benefits. In addition, as an industrial company, Ormat Systems is entitled to accelerated depreciation on equipment used for its industrial activities.

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.

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					98
Consolidated Financial Statements as of December 31, 2006, and 2005 and for Each of the Three Years in the Period Ended December 31, 2006:
Consolidated Balance Sheets					100
Consolidated Statements of Operations and Comprehensive Income					101
Consolidated Statements of Stockholders’ Equity					102
Consolidated Statements of Cash Flows					103
Notes to Consolidated Financial Statements					104
Index to Financial Statements of Ormat Leyte Co. Ltd. ⁽¹⁾
Report of Independent Registered Public Accounting Firm					157
Financial Statements as of December 31, 2005, and for the Year Ended December 31, 2005, including unaudited financial statements as of December 31, 2006 and for the years ended December 31, 2006 and 2004:
Balance Sheets					158
Statements of Income					159
Statements of Changes in Partners’ Equity					160
Statements of Cash Flows					161
Notes to Financial Statements					162


⁽¹⁾	As the Company’s 80% ownership interest in Ormat Leyte Co. Ltd. is accounted for by the equity method, separate financial statements of Ormat Leyte Co. Ltd. have been included pursuant to Rule 3-09 of Regulation S-X.

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Ormat Technologies, Inc.:

We have completed integrated audits of Ormat Technologies, Inc.’s 2006 and 2005 consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, and an audit of its 2004 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Ormat Technologies, Inc. and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes 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. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 12 to the consolidated financial statements, the Company changed the manner in which it accounts for share-based compensation in 2006.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides 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

Table of Contents

only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

San Francisco, California
March 9, 2007

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS


	December 31,
	2006			2005
	(in thousands)
Assets
Current assets:
Cash and cash equivalents		$	20,254		$	26,976
Marketable securities			96,486			43,560
Restricted cash, cash equivalents and marketable securities			56,425			36,732
Receivables:
Trade			36,463			33,515
Related entities			879			524
Other			5,277			2,629
Due from Parent			1,459			—
Inventories, net			7,403			5,224
Costs and estimated earnings in excess of billings on uncompleted contracts			11,216			8,883
Deferred income taxes			1,819			1,663
Prepaid expenses and other			4,911			3,256
Total current assets			242,592			162,962
Unconsolidated investments			37,207			47,235
Deposits and other			15,081			13,489
Deferred income taxes			6,172			5,376
Property, plant and equipment, net			624,089			491,835
Construction-in-process			169,075			128,256
Deferred financing and lease costs, net			15,800			17,412
Intangible assets, net			50,086			47,915
Total assets		$	1,160,102		$	914,480
Liabilities and Stockholders’ Equity
Current liabilities:
Short-term bank credit		$	—		$	3,996
Accounts payable and accrued expenses			70,445			50,048
Billings in excess of costs and estimated earnings on uncompleted contracts			5,803			12,657
Current portion of long-term debt:
Limited and non-recourse			8,482			2,888
Full recourse			1,000			1,000
Senior secured notes (non-recourse)			40,054			23,754
Due to Parent, including current portion of notes payable to Parent			82,379			32,003
Total current liabilities			208,163			126,346
Long-term debt, net of current portion:
Limited and non-recourse			22,157			11,252
Full recourse			1,000			2,000
Senior secured notes (non-recourse)			299,316			324,645
Notes payable to Parent, net of current portion			57,841			140,162
Other liabilities			—			1,309
Deferred lease income			78,883			81,569
Deferred income taxes			21,674			22,004
Liabilities for severance pay			13,378			11,409
Asset retirement obligation			16,832			11,461
Total liabilities			719,244			732,157
Minority interest in net assets of a subsidiary			64			64
Commitments and contingencies (Notes 5, 6, 10, 11, 13, 17 and 18)
Stockholders’ equity:
Common stock, par value $0.001 per share; 200,000,000 shares authorized; 38,101,888 and 31,562,496 shares issued and outstanding, respectively			38			31
Additional paid-in capital			353,399			124,008
Unearned stock-based compensation			—			(153	)
Retained earnings			85,053			55,824
Accumulated other comprehensive income			2,304			2,549
Total stockholders’ equity			440,794			182,259
Total liabilities and stockholders’ equity		$	1,160,102		$	914,480

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

100

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME


	Year Ended December 31,
	2006				2005				2004
	(in thousands, except per share amounts)
Revenues:
Electricity:
Energy and capacity		$	106,682			$	104,975			$	100,281
Lease portion of energy and capacity			86,115				70,963				58,550
Lease income			2,686				1,431				—
Total electricity			195,483				177,369				158,831
Products:
Related party			3,503				7,959				—
Other			69,951				52,664				60,399
Total products			73,454				60,623				60,399
Total revenues			268,937				237,992				219,230
Cost of revenues:
Electricity:
Energy and capacity			77,768				70,328				63,300
Lease portion of energy and capacity			41,345				30,215				26,442
Lease expense			5,243				3,072				—
Total electricity			124,356				103,615				89,742
Products			51,215				45,236				46,336
Total cost of revenues			175,571				148,851				136,078
Gross margin			93,366				89,141				83,152
Operating expenses:
Research and development expenses			2,983				3,036				2,175
Selling and marketing expenses			10,361				7,876				7,769
General and administrative expenses			18,094				14,320				11,609
Gain on sale of geothermal resource rights			—				—				(845	)
Operating income			61,928				63,909				62,444
Other income (expense):
Interest income			6,560				4,308				1,316
Interest expense:
Parent			(8,367	)			(10,635	)			(9,723	)
Other			(30,674	)			(48,186	)			(33,690	)
Less — amount capitalized			8,080				3,504				628
Foreign currency translation and transaction losses			(704	)			(439	)			(146	)
Other non-operating income			694				512				112
Income before income taxes, minority interest, and equity in income of investees			37,517				12,973				20,941
Income tax provision			(6,403	)			(4,690	)			(6,609	)
Minority interest in earnings of subsidiaries			(813	)			—				(108	)
Equity in income of investees			4,146				6,894				3,567
Net income			34,447				15,177				17,791
Other comprehensive income (loss), net of related taxes:
Gain (loss) in respect of derivative instruments designated for cash flow hedge (net of related tax of $0, $1,518,000 and $(198,000), respectively)			—				2,295				(322	)
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of ($224,000), $347,000 and $0, respectively)			(362	)			563				—
Change in unrealized gains or losses on marketable available-for-sale securities available-for-sale (net of related tax of $100,000, $8,000 and $0, respectively)			117				13				—
Comprehensive income		$	34,202			$	18,048			$	17,469
Earnings per share:
Basic		$	1.00			$	0.48			$	0.72
Diluted		$	0.99			$	0.48			$	0.72
Weighted average number of shares used in computation of earnings per share:
Basic			34,593				31,563				24,806
Diluted			34,707				31,609				24,806

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

101

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY


	Common Stock					Additional Paid-in Capital				Divisional Deficit				Unearned Stock-based Compensation				Retained Earnings				Accumulated Other Comprehensive Income(Loss)				Total
	Shares		Amount			Additional Paid-in Capital				Divisional Deficit				Unearned Stock-based Compensation				Retained Earnings				Accumulated Other Comprehensive Income(Loss)				Total
	(in thousands, except per share data)
Balance at December 31, 2003		23,214			23			7,002				(11,263	)			(86	)			41,299				—				36,975
Unearned stock-based compensation		—			—			52				—				(52	)			—				—				—
Amortization of unearned stock-based compensation		—			—			—				—				61				—				—				61
Conversion of note payable to Parent to equity		1,161			1			19,999				—				—				—				—				20,000
Reclassification of divisional deficit		—			—			—				10,236				(167	)			(10,069	)			—				—
Distribution to Parent for purchase of OSL (net of related tax of $3,747,000)		—			—			—				—				—				(1,053	)			—				(1,053	)
Cash dividend declared, $0.1025 per share		—			—			—				—				—				(2,500	)			—				(2,500	)
Issuance of common stock in initial public offering		7,188			7			96,955				—				—				—				—				96,962
Net income		—			—			—				1,027				—				16,764				—				17,791
Loss in respect of derivative instruments designated for cash flow hedge (net of related tax benefit of $198,000)		—			—			—				—				—				—				(322	)			(322	)
Balance at December 31, 2004		31,563			31			124,008				—				(244	)			44,441				(322	)			167,914
Amortization of unearned stock-based compensation		—			—			—				—				91				—				—				91
Cash dividend declared, $0.12 per share		—			—			—				—				—				(3,794	)			—				(3,794	)
Net income		—			—			—				—				—				15,177				—				15,177
Other comprehensive income, net of related taxes:
Gain in respect of derivative instruments designated for cash flow hedge (net of related tax of $1,518,000)		—			—			—				—				—				—				2,295				2,295
Amortization of unrealized losses in respect of derivative instruments designated for cash flow hedge (net of related tax benefit of $347,000)																								563				563
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $8,000)		—			—			—				—				—				—				13				13
Balance at December 31, 2005		31,563		$	31		$	124,008			$	—			$	(153	)		$	55,824			$	2,549			$	182,259
Reversal of deferred stock based compensation		—			—			(153	)							153				—				—				—
Share based compensation		—			—			1,706								—				—				—				1,706
Cash dividend declared, $0.15 per share		—			—			—								—				(5,218	)			—				(5,218	)
Issuance of shares of common stock in a follow-on public offering		4,025			4			135,049																				135,053
Issuance of shares of common stock in a Block Trade transaction		2,500			3			92,408																				92,411
Exercise of options by employees		14			—			215																				215
Tax benefit on exercise of options by employees								166																				166
Net income		—			—			—								—				34,447				—				34,447
Other comprehensive income, net of related taxes:
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax benefit of $224,000)		—			—			—								—				—				(362	)			(362	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $100,000)		—			—			—								—				—				117				117
Balance at December 31, 2006		38,102		$	38		$	353,399			$	—			$	—			$	85,053			$	2,304			$	440,794

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

102

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2006				2005				2004
	(in thousands)
Cash flows from operating activities:
Net income		$	34,447			$	15,177			$	17,791
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			43,439				36,006				34,695
Accretion of asset retirement obligation			971				774				588
Share-based compensation			1,706				—				—
Amortization of deferred lease income			(2,686	)			(1,431	)			—
Extinguishment of deferred financing costs			—				4,180				776
Minority interest in earnings of subsidiaries			813				—				108
Equity in income of investees			(4,146	)			(6,894	)			(3,567	)
Distributions from unconsolidated investments			4,503				5,694				3,996
Realization of loss related to interest rate cap transactions			—				910				1,637
Gain on sale of geothermal resource rights			—				—				(845	)
Unrealized loss in respect of derivative instruments, net			559				—				—
Loss (gain) on severace pay fund asset			(1,095	)			302				122
Deferred income tax provision (benefit)			(1,528	)			(2,182	)			3,785
Changes in operating assets and liabilities, net of acquisitions:
Receivables			(2,502	)			(7,415	)			3,004
Costs and estimated earnings in excess of billings on uncompleted contracts			(2,333	)			(5,719	)			(1,242	)
Inventories			(2,179	)			822				(2,334	)
Prepaid expenses and other			(1,573	)			(879	)			(334	)
Deposits and other			(184	)			(335	)			1,576
Accounts payable and accrued expenses			12,094				7,171				5,099
Due from/to related entities, net			(609	)			1,889				(627	)
Billings in excess of costs and estimated earnings on uncompleted contracts			(6,854	)			6,518				(1,704	)
Other liabilities			(20	)			(80	)			(80	)
Proceeds from operating lease transaction			—				83,000				—
Deferred lease transaction costs			—				(3,266	)			—
Liabilities for severance pay			1,969				696				1,014
Due from Parent			(1,757	)			—				—
Net cash provided by operating activities			73,035				134,938				63,458
Cash flows from investing activities:
Distributions from unconsolidated investments			2,794				2,844				2,500
Marketable securities, net			(52,654	)			45,606				(90,916	)
Net change in restricted cash, cash equivalents and marketable securities			(16,285	)			(13,696	)			(9,039	)
Capital expenditures			(159,497	)			(116,749	)			(38,122	)
Decrease of cash resulting from deconsolidation of OLCL			—				—				(1,801	)
Proceeds from sale of geothermal resource rights			—				—				2,420
Cash paid for acquisitions, net of cash received			(22,760	)			—				(175,950	)
Intangible asset acquired			—				(1,800	)			—
Increase in severance pay fund asset, net			(872	)			(503	)			(463	)
Repayment from unconsolidated investment			127				890				788
Net cash used in investing activities			(249,147	)			(83,408	)			(310,583	)
Cash flows from financing activities:
Due to Parent, net			(31,647	)			(40,175	)			50,836
Proceeds from public offerings, net of issuance costs			227,464				—				96,962
Proceeds from exercise of options by employees			215				—				—
Proceeds from interest rate lock transactions			—				4,334				—
Proceeds from short term bank credit			—				3,996				—
Proceeds from issuance of long-term debt			—				165,000				210,000
Repayments of short-term and long-term debt			(20,736	)			(183,975	)			(68,194	)
Deferred debt issuance costs			(688	)			(4,190	)			(10,782	)
Payment for interest rate caps			—				—				(3,820	)
Cash dividends paid			(5,218	)			(6,294	)			—
Net cash provided by (used in) financing activities			169,390				(61,304	)			275,002
Net increase (decrease) in cash and cash equivalents			(6,722	)			(9,774	)			27,877
Cash and cash equivalents at beginning of period			26,976				36,750				8,873
Cash and cash equivalents at end of period		$	20,254			$	26,976			$	36,750
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest, net of interest capitalized		$	14,406			$	24,266			$	28,531
Income taxes		$	7,417			$	2,690			$	9
Supplemental non-cash investing and financing activities:
Conversion of note payable to Parent to equity		$	—			$	—			$	20,000
Increase in accounts payable related to purchases of property, plant and equipment		$	7,146			$	7,527			$	1,306
Accrued liabilities for deferred debt issuance and lease costs		$	—			$	285			$	—
Increase in asset retirement cost and asset retirement obligation		$	4,400			$	22			$	2,210
Cash dividend declared		$	—			$	—			$	2,500
Acquisitions — See Notes 2 and 5

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

103

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, Nicaragua, the Philippines and Guatemala. The Company’s equipment manufacturing operations are located in Israel.

Most of the Company’s domestic power plant facilities are Qualifying Facilities under the Public Utility Regulatory Policies Act of 1978 (‘‘PURPA’’). The power purchase agreements 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, 2006.

Recapitalization

On June 29, 2004, the Company amended and restated its certificate of incorporation, pursuant to which the authorized capital stock of the Company was increased from 754 shares of $1.00 par value common stock to 155,892,833 authorized shares, comprised of 150,892,833 shares of $0.001 par value common stock and 5,000,000 shares of $0.001 par value preferred stock, of which 500,000 shares have been designated as Series A Preferred Stock. The Company’s Board of Directors has the authority to issue the undesignated preferred stock in one or more series and to establish the rights, preferences, privileges and restrictions thereof. On October 21, 2004, the Company further amended and restated its certificate of incorporation, pursuant to which the authorized capital stock of the Company was increased from 150,892,833 shares of $0.001 common stock immediately following the split (see below) to 200,000,000 authorized shares of $0.001 par value common stock.

Additionally, on June 29, 2004, the issued and outstanding 151 shares of $1.00 par value common stock were divided and converted (stock split) to 23,214,281 shares of $0.001 par value common stock.

Further, on June 29, 2004, $20.0 million outstanding pursuant to the note payable to the Parent was converted to 1,160,714 shares of $0.001 par value common stock of the Company. Such conversion reduced the amounts payable pursuant to the Parent Loan Agreement and increased the stockholder’s equity by $20.0 million. No gain or loss was recognized as a result of the conversion.

On October 21, 2004, the Board of Directors approved a 1-for-1.325444 reverse stock split of the Company’s common stock. Accordingly, all common share and per common share amounts in these consolidated financial statements have been restated to give retroactive effect to the reverse stock split for all years presented. The par value of the common stock remained at $0.001 per share.

Cash dividend

On October 21, 2004, the Company’s Board of Directors declared, approved and authorized the payment of a cash dividend in the aggregate amount of $2.5 million ($0.1025 per share). Such dividend was paid on March 2, 2005 and was presented in the balance sheet as of December 31, 2004, in the ‘‘Due to Parent’’ balance.

During the year ended December 31, 2005, the Company’s Board of Directors declared, approved and authorized the payment of cash dividends in the aggregate amount of $3.8 million ($0.12 per share). Such dividends were paid during the year ended December 31, 2005.

104

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During the year ended December 31, 2006, the Company’s Board of Directors declared, approved and authorized the payment of cash dividends in the aggregate amount of $5.2 million ($0.15 per share). Such dividends were paid during the year ended December 31, 2006.

Initial public offering

In November 2004, the Company completed an initial public offering (‘‘IPO’’) of 7,187,500 shares of common stock. Net proceeds to the Company after deducting underwriting fees and offering related expenses, were approximately $97.0 million.

Shelf Registration statement, Follow-On Public Offering and Sale of Shares in a Block Trade

On January 17, 2006, the Company filed a universal shelf registration statement on Form S-3, which was declared effective by the SEC on January 31, 2006. The shelf registration statement 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 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.

On April 10, 2006, the Company completed a follow-on public offering of 3,500,000 shares of common stock at a price of $35.50 per share, under the shelf registration statement mentioned above. In addition, on April 17, 2006, 525,000 additional shares of common stock were sold at the abovementioned price pursuant to the exercise of the underwriters’ over-allotment option. Net proceeds to the Company after deducting underwriting fees and commissions and estimated offering expenses associated with the offering were approximately $135.1 million.

On December 19, 2006, the Company completed a sale of 2,500,000 shares of common stock to Lehman Brothers in a block trade at a price of $37.50 per share, under the shelf registration statement mentioned above. Net proceeds to the Company after deducting underwriting fees and commissions and estimated offering expenses associated with the offering were approximately $92.4 million.

Rounding

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

Reclassification

Certain comparative figures have been reclassified to conform to the current year presentation.

Basis of presentation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The Company has an 85% interest in OrYunnan Geothermal Co. Ltd. (‘‘OrYunnan’’) that is accounted for under the consolidation method of accounting and an 80% interest in Ormat Leyte Co. Ltd. (‘‘OLCL’’) that was accounted for under the consolidation method of accounting until March 31, 2004 and under the equity method of accounting thereafter. The Company’s investment in Orzunil I de Electricidad, Limitada (‘‘Orzunil’’) was consolidated beginning March 13, 2006 when the Company increased its ownership interest to 71.8%. On August 16, 2006, the Company increased its ownership interest to 100% (see Note 5). Prior to March 13, 2006, this investment was accounted for using the equity method of accounting. Intercompany accounts and transactions have been eliminated in the consolidation.

105

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In November 1999, the Company, through a wholly owned subsidiary, entered into an agreement with Yunnan Province Geothermal Development Co. (‘‘YPGD’’) to form OrYunnan, a limited liability joint venture, whereby the Company is to contribute, for an 85% ownership interest, $2,550,000 and YPGD is to contribute, for the remaining 15% ownership interest, $450,000. Pursuant to such agreement, 15% of the capital contribution was made in April 2000, and the remaining portion is to be paid within 60 days after the date on which a power purchase agreement is executed. OrYunnan is currently in the process of negotiating a power purchase agreement. OrYunnan was formed for the purpose of utilizing, for electric power generation, all of the geothermal resources of Teng Chong County of the Yunnan Province in the People’s Republic of China.

OLCL is a limited partnership established for the purpose of developing, financing, constructing, owning, operating, and maintaining geothermal power plants in Leyte Province, the Philippines.

The Company accounts for its interests in partnerships and companies in which it has equal to or less than a 50% ownership interest under the equity method. 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’’ on the Company’s consolidated statements of operations and comprehensive income.

Adoption of FIN No. 46R

In January 2003, the Financial Accounting Standards Board (‘‘FASB’’) issued Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB 51 (‘‘FIN No. 46’’), and amended it by issuing FIN No. 46R in December 2003. Among other things, FIN No. 46R generally deferred the effective date of FIN No. 46 to the quarter ended March 31, 2004. The objectives of FIN No. 46R are to provide guidance on the identification of Variable Interest Entities (‘‘VIEs’’) for which control is achieved through means other than ownership of a majority of the voting interest of the entity, and how to determine which company (if any), as the primary beneficiary, should consolidate the VIE. A variable interest in a VIE, by definition, is an asset, liability, equity, contractual arrangement or other economic interest that absorbs the entity’s economic variability.

Effective as of March 31, 2004, the Company adopted FIN No. 46R. In connection with the adoption of FIN No. 46R, the Company concluded that OLCL, in which the Company has an 80% ownership interest, should be deconsolidated. OLCL’s operating results continued to be accounted for using the consolidation method of accounting for the three month period ended March 31, 2004. Effective April 1, 2004, the Company’s ownership interest in OLCL is accounted for using the equity method of accounting. The Company’s maximum exposure to loss as a result of its involvement with OLCL is estimated to be $5.3 million, which is the Company’s net investment at December 31, 2006.

The Company also has variable interests in certain other consolidated wholly owned VIEs that will continue to be consolidated because the Company is the primary beneficiary. Further, the Company has concluded that the Company’s remaining significant equity investments do not require consolidation as they are not VIEs.

Purchase of the power generation business from the Parent

As of July 1, 2004, a wholly owned subsidiary of the Company, Ormat Systems Ltd. (‘‘OSL’’), an Israeli company, acquired from the Parent for $11.0 million the power generation business which includes the manufacturing and sale of energy-related products pertaining mainly to the geothermal and recovered energy industry.

The Company considers this business to be synergistic with its ownership and operation of geothermal power plants as well as to the construction of the projects (on a turnkey basis). In addition

106

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

to acquiring the tangible net assets of the power generation business, OSL assumed the title and interest to: (i) certain related contracts; and (ii) liabilities and rights under agreements with employees and consultants, and obtained a perpetual license of all intellectual property pertaining to the power generation business from the Parent.

In connection with the acquisition, OSL and the Parent have entered into an agreement whereby OSL will provide to the Parent, for a monthly fee of $10,000 (adjusted annually partially for changes in the Israeli Consumer Price Index), certain corporate administrative services, including the services of executive officers. In addition, OSL has agreed to provide the Parent with services of certain skilled engineers at OSL’s cost plus 10%. Such agreements may be terminated by either party after the initial term which ends in 2009.

Also in connection with the acquisition, OSL entered into a rental agreement with the Parent for the use 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 tax and other costs to maintain the properties. The term of the rental agreement is 59 months and it expires in June 2009, which term has been extended by a consent of the Israeli Land Administration for a period the shorter of: (i) 25 years (including the initial term) or (ii) the remaining period of the underlying lease agreement with the Israel Land Administration (which terminates between 2018 and 2047).

The Company has recorded the purchase of the power generation business at historical net book value, and has accounted for the purchase as a transfer of assets between entities under common control in a manner similar to the pooling of interests; accordingly, all prior period consolidated financial statements of the Company have been restated to include the results of operations, financial position, and cash flows of the power generation business.

The financial statements for all years presented include the historical financial information of the Company prior to the acquisition of the power generation business, combined with the historical financial information of the acquired power generation business which was carved out of the Parent for all years presented. The difference between the assets and liabilities of the power generation business consists of accumulated retained earnings (deficit) as well as amounts due to/from Parent resulting from cash transfers. Such amounts have been aggregated and presented in the statements of stockholders’ equity as ‘‘divisional deficit’’ because it is not possible to distinguish the beginning balance as the records were not available to accurately break out the two components. On July 1, 2004, the effective date of the transaction, the divisional deficit was reclassified to retained earnings and unearned stock-based compensation. Retained earnings in the statements of stockholders’ equity for all years prior to the year ended December 31, 2004 represent the retained earnings of the Company prior to the acquisition of the power generation business.

The preparation of these financial statements included the use of ‘‘carve out’’ accounting procedures wherein certain assets, liabilities, revenues and expenses historically recorded or incurred at the Parent level, which were related to OSL, have been identified and allocated as appropriate to present the financial position, operating results, and cash flows of OSL for the years presented.

The statements of operations for OSL for the period from January 1, 2004 to June 30, 2004 were carved out using specific identification for revenues and cost of revenues, research and development expense, selling and marketing expenses, general and administrative expenses and interest income and expense. The income tax provision was recalculated based on the separate return method pursuant to Statement of Financial Accounting Standards (‘‘SFAS’’) No. 109, Accounting for Income Taxes .

Of the $11.0 million purchase price, the Company paid $4.8 million in cash and assumed $6.2 million in debt and other liabilities. The excess of the consideration paid over the historical net book value of the purchased business has been recorded as a distribution to the Parent, which reduced stockholders’ equity by approximately $4.8 million at July 1, 2004. Because the deferred income taxes

107

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

at June 30, 2004 had a full valuation allowance, there was no tax effect for the difference between the book and tax basis of the purchased assets and liabilities.

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

Marketable securities consist of debt securities (mainly auction rate securities and commercial papers). The Company accounts for such securities in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities. The Company determines the appropriate classification of all marketable securities as held-to-maturity, available-for-sale or trading at the time of the purchase and re-evaluates such classification at each balance sheet date. At December 31, 2006 and 2005 all of the Company’s investments in marketable securities were classified as available-for-sale securities and as a result, were reported at their fair value based upon the quoted market prices of such securities at year end. Net unrealized gains or losses are reported as a component of accumulated other comprehensive income (loss) in stockholders’ equity. Net realized gains or losses are reported in interest income.

The marketable securities are included in the balance sheets at December 31, 2006 and 2005, as follows:


	December 31,
	2006			2005
	(dollars in thousands)
Marketable securities		$	96,486		$	43,560
Amount presented among short-term restricted cash,
cash equivalents and marketable securities			16,921			14,645
Total		$	113,407		$	58,205

The cost of the marketable securities at December 31, 2006 and 2005 was $113,232,000 and $58,224,000, respectively.

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 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. Such amounts are invested primarily in money market accounts, auction rate securities and commercial papers with a minimum investment grade of ‘‘AA’’. Auction rate securities are classified as available-for-sale.

Certain of the restricted cash accounts can be replaced by a letter of credit, and as further described in Note 18, as of December 31, 2006, three letters of credit aggregating $21.9 million were issued by the Company to release restriction on funds that were used as collateral for OFC’s 8¼% Senior Secured Notes (‘‘OFC Senior Secured Notes’’) and OrCal’s 6.21% Senior Secured Notes (‘‘OrCal Senior Secured Notes’’).

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.

108

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2006 and 2005, the Company had deposits totaling $13,068,000 and $9,889,000, respectively, in six and four, respectively, U.S. financial institutions that were federally insured up to $100,000 per account. At December 31, 2006 and 2005, the Company’s deposits in foreign countries of approximately $15,321,000 and $11,935,000, respectively, were not insured.

At December 31, 2006 and 2005, accounts receivable related to operations in foreign countries amounted to approximately $16,957,000 and $11,017,000, respectively. At December 31, 2006 and 2005, accounts receivable from the Company’s major customers that have generated 10% or more of its revenues (see Note 15) amounted to approximately 49% and 59%, respectively, of the Company’s accounts receivable.

Southern California Edison Company (‘‘SCE’’) accounted for 30.0%, 36.1% and 41.4% of the Company’s total revenues for the years ended December 31, 2006, 2005 and 2004, respectively. SCE is also the power purchaser and revenue source for the Mammoth project, which is accounted for separately under the equity method.

Sierra Pacific Power Company accounted for 12.8%, 14.1% and 12.9% of the Company’s total revenues for the years ended December 31, 2006, 2005 and 2004, respectively.

Hawaii Electric Light Company accounted for 15.1%, 15.2% and 7.1% of the Company’s total revenues for the years ended December 31, 2006, 2005 and 2004, 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 moving-average cost method and are stated net of provision for slow-moving and obsolescence, which was not significant at December 31, 2006 and 2005.

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 incurred as part of the 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 are depreciated using the straight-line method over the term of the relevant power purchase agreement, which range from 12 to 25 years (see Note 13). The geothermal power plant in Nicaragua is to be fully depreciated over the period that the plants are owned by the Company. The other assets are depreciated using the straight-line method over the following estimated useful lives of the assets:

109

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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

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

The Company capitalizes interest costs as part of constructing power plant facilities. Such capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life. Capitalized interest costs amounted to $8,080,000, $3,504,000 and $628,000 for the years ended December 31, 2006, 2005 and 2004, respectively.

Asset retirement obligation

As required by SFAS No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets , which was amended by FASB Interpretation (‘‘FIN’’) No. 47, Accounting for Conditional Retirement Obligations, an Interpretation of FASB Statement No. 143 , 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 geothermal 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 statement of operations. Accumulated amortization related to deferred financing costs amounted to $4,342,000 and $2,422,000 at December 31, 2006 and 2005, respectively. Amortization expense for the years ended December 31, 2006, 2005 and 2004 amounted to $1,920,000, $6,087,000 and $2,705,000, respectively. Amortization expense for the year ended December 31, 2005 includes $4,180,000 relating to the write-off of the remaining deferred financing costs when the Beal Bank loan was repaid (see Note 9).

Deferred transaction costs relating to the Puna operating leases (see Note 10) in the amount of $4,333,000 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 statement of operations. Accumulated amortization related to deferred lease costs amounted to $301,000 and $117,000 at December 31, 2006 and 2005, respectively. Amortization expense for the years ended December 31, 2006 and 2005 amounted to $184,000 and $117,000, respectively.

110

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Intangible assets

Intangible assets consist of allocated acquisition costs of power purchase agreements, which are amortized over the 13 to 25-year terms of the agreements using the straight-line method.

Impairment of long-lived assets and long-lived assets to be disposed of

Long-lived assets which consist of property, plant and equipment, power purchase agreements andunconsolidated investments are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net undiscounted cash flows expected to be generated by the asset. If such 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 the fair value of the assets. 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, future estimates as to the recoverability of such assets may change based on revised circumstances.

Derivative instruments

Derivative instruments (including certain derivative instruments embedded in other contracts) are measured at their fair value and recorded as either assets or liabilities unless exempted from derivative treatment as a normal purchase and sale. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met, which requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

The Company maintains a risk management strategy that incorporates the use of interest rate swaps and interest rate caps to minimize significant fluctuation in cash flows and/or earnings that are caused by 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 interest on the related debt is paid. Gains or losses on contracts that are not designated to qualify as a cash flow hedge are included as a component of interest expense.

Foreign currency translation

The functional currency of all foreign entities is the reporting currency (U.S. dollar). For these entities, monetary assets and liabilities are translated at the current exchange rate, while non-monetary items are translated at historical rates. Income and expense items are translated at the average exchange rate for the year, except for depreciation, which is translated at historical rates. Translation adjustments and transaction gains or losses are included in results of operations.

Comprehensive income reporting

Comprehensive income includes net income plus other comprehensive income, which for the Company consists of unrealized gain or loss on marketable securities available-for-sale 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.

111

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. For power purchase agreements (‘‘PPAs’’) agreed to, modified or acquired in business combinations on or after July 1, 2003 (effective date of Emerging Issues Task Force Issue (‘‘EITF’’) No. 01-08, Determining whether an Arrangement Contains a Lease ), revenues related to the lease element of the PPAs are included as ‘‘lease portion of energy and capacity’’ revenues, with the remaining revenues related to the production and delivery of energy presented as ‘‘energy and capacity’’. Lease income and expense are recognized ratably over the lease periods.

Revenues from engineering, operating services, and parts and product sales are recorded upon providing the service or delivery of the products and parts. Revenues from the supply and/or construction of geothermal and recovered energy power plant equipment and other equipment on behalf of others are recognized on the percentage completion method. Revenue is 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, 2006, 2005 and 2004.

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 $252,000, $1,275,000 and $86,000 during the years ended December 31, 2006, 2005, and 2004, respectively.

Advertising expense

Advertising costs are expensed as incurred and totaled $96,000, $180,000 and $74,000 for the years ended December 31, 2006, 2005, and 2004, respectively.

Patent expense

Patents are internally developed, and therefore costs are expensed as incurred and totaled $122,000, $252,000 and $290,000 for the years ended December 31, 2006, 2005, and 2004, respectively.

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

112

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

anticipated. The Company accounts for investment tax credits and production tax credits as a reduction to income taxes in the year in which the credit arises. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that, based on available evidence, are more likely than not expected to be realized.

Earnings per share

Basic earnings per share is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding for the year. The Company does not have any equity instruments that are dilutive, except for employee stock options which were granted in the years ended December 31, 2006, 2005 and 2004 and whose dilutive effect on the earnings per share for the years ended December 31, 2005 and 2004 is immaterial. The stock options granted to employees of the Company in the Parent’s stock are not dilutive to the Company’s earnings per share.

Fair value of financial instruments

The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of those instruments. Marketable securities are presented at fair value. The fair value of long-term debt is estimated based on the current borrowing rates for similar issues, which approximates carrying amount for long-term debt, except for the following debt:


	Fair Value						Carrying Amount
	December 31,						December 31,
	2006			2005			2006			2005
	(dollars in millions)						(dollars in millions)
Senior loans:
International Finance Corporation Loan A		$	7.5		$	—		$	7.0		$	—
International Finance Corporation Loan B			4.0			—			3.9			—
Commonwealth Development Corporation Loan			8.7			—			8.5			—
Senior Secured Notes:
Ormat Funding Corp. (‘‘OFC’’)			182.3			185.2			178.7			183.4
OrCal Geothermal Inc. (‘‘OrCal’’)			151.5			165.0			160.7			165.0
Parent’s Loan			90.8			125.2			89.5			121.1
Parent’s Note			47.8			45.3			50.7			50.7

Accounting estimates

The preparation of financial statements in conformity with generally accepted accounting principles 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.

New accounting pronouncements

New accounting pronouncements effective in the year ended December 31, 2006

SFAS No. 123R — Share-Based Payments

Effective January 1, 2006, the Company adopted SFAS No. 123(R), Share-Based Payments , (‘‘SFAS No. 123R’’), which establishes the accounting for employee stock-based awards. Prior to

113

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

January 1, 2006, the Company accounted for stock-based compensation in accordance with the provisions of Accounting Principles Board Opinion No. 25 (‘‘APB No. 25’’), Accounting for Stock Issued to Employees , and related interpretations. Under APB No. 25, compensation cost was recognized based on the difference, if any, on the date of grant between the fair value of the Company’s stock and the amount an employee must pay to acquire the stock (see Note 12).

SFAS No. 151 — Inventory Costs

In November 2004, the FASB issued SFAS No. 151, Inventory Costs — An Amendment of ARB 43, Chapter 4 . SFAS No. 151 amends the guidance in ARB No. 43, Chapter 4, Inventory Pricing , to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material. SFAS No. 151 requires that those items be recognized as current period charges. In addition, SFAS No. 151 requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. The provisions of SFAS No. 151 are applied prospectively to inventory costs incurred beginning January 1, 2006. The adoption by the Company of SFAS No. 151, effective January 1, 2006, did not have any impact on its results of operations or financial position.

SFAS No. 154 — Accounting Changes and Error Corrections

In June 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. SFAS No. 154 replaces APB Opinion No. 20, Accounting Changes and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements . SFAS No. 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented based on the new accounting principle. SFAS No. 154 also requires that a change in method of depreciating or amortizing a long-lived non-financial asset be accounted for prospectively as a change in estimate, and correction of errors in previously issued financial statements should be termed a restatement. SFAS No. 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005 (January 1, 2006 for the Company). The adoption by the Company of SFAS No. 154, effective January 1, 2006, did not have any impact on its results of operations or financial position.

EITF Issue No. 04-5 — Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights

In June 2005, the FASB issued EITF Issue No. 04-5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights . EITF Issue No. 04-5 provides guidance in determining whether a general partner controls a limited partnership and therefore should consolidate the limited partnership. EITF Issue No. 04-5 states that the general partner in a limited partnership is presumed to control that limited partnership and that the presumption may be overcome if the limited partners have either: (i) the substantive ability to dissolve or liquidate the limited partnership or otherwise remove the general partner without cause, or (ii) substantive participating rights. The effective date for applying the guidance in EITF No. 04-5 was: (i) June 29, 2005 for all new limited partnerships and existing limited partnerships for which the partnership agreement was modified after that date, and (ii) no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005 (January 1, 2006 for the Company), for all other limited partnerships. The adoption by the Company of EITF Issue No. 04-5, effective January 1, 2006, did not have any impact on the Company’s consolidated financial statements.

SAB No. 108 — Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements

In September 2006, the SEC issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (‘‘ SAB

114

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

No. 108’’). SAB No. 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year’s misstatement. The SEC staff believes that registrants should quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in a misstatement that, when all relevant quantitative and qualitative factors are considered, is material and therefore must be quantified. SAB No. 108 is effective for fiscal years ending on or after November 15, 2006 (December 31, 2006 for the Company). The adoption by the Company of SAB No. 108, effective December 31, 2006, did not have any impact on its results of operations and financial position.

New accounting pronouncements effective in future years

SFAS No. 155 — Accounting for Certain Hybrid Financial Instruments

In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments . SFAS No. 155 replaces certain provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities . SFAS No. 155 permits fair value measurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation. It clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS No. 133. SFAS No. 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. It also clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS No. 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued after January 1, 2007. The Company does not expect that the adoption of SFAS No. 155 will have a material impact on its results of operations or financial position in future periods.

FIN No. 48 — Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109

In June 2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109 . FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes . FIN No. 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN No. 48 is effective January 1, 2007. The Company is currently assessing the impact of FIN No. 48 and has not yet determined the impact that its adoption will have on its results of operations and financial position.

EITF Issue No. 06-3 — How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That is, Gross versus Net Presentation)

In June 2006, the FASB issued EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That is, Gross versus Net Presentation ). The requirements of EITF Issue No. 06-3 apply to any tax assessed by a governmental authority that is imposed concurrently on a specific revenue-producing transaction between a seller and a customer. Examples of taxes subject to Issue No. 06-3 include sales, use, value added, and some excise taxes. EITF Issue No. 06-3 excludes taxes that are assessed on gross receipts or that are imposed during the process of obtaining inventory. Companies will be required to disclose

115

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

their accounting policy regarding the presentation of taxes subject to EITF Issue No. 06-3, and the amounts of such taxes that are included in income on a gross basis, if those amounts are significant. EITF Issue No. 06-3 is effective January 1, 2007. The Company does not expect EITF Issue No. 06-3 to have an impact on its financial statements in future periods.

SFAS No. 157 — Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements . SFAS No. 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 (January 1, 2008 for the Company) and interim periods within those fiscal years, with early adoption permitted. The Company is currently assessing the impact of SFAS No. 157, and has not yet determined the impact that its adoption will have on its results of operations or financial position.

NOTE 2 — BUSINESS ACQUISITIONS

The Steamboat 2/3 Project and Meyberg Property

On February 11, 2004, the Company acquired 100% of the outstanding shares of capital stock of Steamboat Development Corp. (‘‘SDC’’) and certain real property (‘‘Meyberg Property’’) from an unrelated party. SDC owned certain leasehold interests as a lessee in the two Steamboat 2/3 geothermal power plants and certain related geothermal leases. On February 13, 2004, the Company acquired all of the beneficial rights, title, and interest in the Steamboat 2/3 geothermal power plants from the lessor. The Company acquired SDC and the Meyberg Property to increase its geothermal power plant operations in the U.S. The Company acquired the lessee and lessor positions of the Steamboat 2/3 geothermal power plants for a combined purchase price of approximately $82.0 million, plus transaction cost of approximately $0.8 million. The results of SDC’s operations have been included in the consolidated financial statements since February 11, 2004.

The Steamboat Hills Project

On May 20, 2004, the Company completed the acquisition of 100% of the equity interests of Yankee Caithness Joint Venture, L.P. (‘‘Yankee’’), which was subsequently renamed as Steamboat Hills, from unrelated parties for a purchase price of approximately $20.3 million, including acquisition costs of approximately $0.1 million. Yankee owns and operates a geothermal electric generation plant, located in Steamboat Springs, Nevada. The Company purchased Yankee in order to increase its geothermal power plant operations. The results of Steamboat Hills’ operations have been included in the consolidated financial statements since May 20, 2004.

The Puna Project

On June 3, 2004, the Company completed the acquisition of 100% of the equity interests of Puna Geothermal Venture (‘‘PGV’’) from an unrelated party for a purchase price of $72.9 million, including acquisition costs of approximately $0.2 million. PGV operates a geothermal power plant (‘‘Puna Project’’) located on the Big Island of Hawaii. The Company purchased PGV in order to increase its geothermal power plant operations in the U.S. The results of PGV’s operations have been included in the consolidated financial statements since June 3, 2004.

The Steamboat 2/3 Project, the Meyberg Property, the Steamboat Hills Project and the Puna Project acquisitions have been accounted for under the purchase method of accounting and the

116

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

acquired depreciable assets and intangibles are being depreciated over their estimated useful lives of 14 to 23 years. The purchase price (including of the lessee and lessor position in the Steamboat 2/3 Project) has been allocated to the fair value of assets and liabilities based on independent valuations and management’s estimates as follows:


	Steamboat 2/3 Project and Meyberg Property				Steamboat Hills Project				Puna Project				Total
	(dollars in thousands)
Accounts receivable assumed		$	1,944			$	—			$	1,870			$	3,814
Property, plant and equipment			78,719				20,809				56,881				156,409
Intangibles (power purchase agreement)			4,499				—				14,992				19,491
Accounts payable and other liabilities assumed			(1,455	)			—				(179	)			(1,634	)
Asset retirement obligation			(941	)			(548	)			(641	)			(2,130	)
Total cash paid		$	82,766			$	20,261			$	72,923			$	175,950

The following unaudited pro forma financial information for the year ended December 31, 2004 assumes the Steamboat 2/3 Project and Meyberg Property, the Steamboat Hills Project and the Puna Project acquisitions occurred as of the beginning of the year, after giving effect to certain adjustments, including the amortization of intangible assets, interest expense on acquisition debt, 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 the Steamboat 2/3 Project and Meyberg Property, the Steamboat Hills Project and the Puna Project been affected on the date indicated.


	Year Ended December 31, 2004
	(dollars in thousands, except per share amounts)
Revenues		$	231,788
Net income			17,789
Basic and diluted earnings per share		$	0.72

The Zunil Project

On March 13, 2006 and on August 16, 2006, the Company acquired an additional 50.8% and 28.2%, respectively, ownership interest in Orzunil I de Electricidad, Limitada (‘‘Orzunil’’), thereby increasing the Company’s ownership interest to 100% (see Note 5).

117

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3 — INVENTORIES

Inventories consist of the following:


	December 31,
	2006			2005
	(dollars in thousands)
Raw materials and purchased parts for assembly		$	3,397		$	1,521
Self-manufactured assembly parts and finished products			4,006			3,703
Total		$	7,403		$	5,224

NOTE 4 — COST AND ESTIMATED EARNINGS ON UNCOMPLETED CONTRACTS


	December 31,
	2006			2005
	(dollars in thousands)
Costs and estimated earnings incurred on uncompleted contracts		$	18,967		$	39,142
Less billings to date			13,554			42,916
Total		$	5,413		$	(3,774	)

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


	December 31,
	2006				2005
	(dollars in thousands)
Costs and estimated earnings in excess of billings on uncompleted contracts		$	11,216			$	8,883
Billings in excess of costs and estimated earnings on uncompleted contracts			(5,803	)			(12,657	)
Total		$	5,413			$	(3,774	)

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.

118

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5 — UNCONSOLIDATED INVESTMENTS

Unconsolidated investments in power plant projects consist of the following:


	December 31,
	2006			2005
	(dollars in thousands)
Orzunil:
Investment		$	—		$	3,807
Advances			—			3,712
			—			7,519
Mammoth			31,913			34,240
OLCL			5,294			5,476
Total		$	37,207		$	47,235

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

The Zunil Project

Prior to March 13, 2006, the Company had a 21.0% ownership interest in Orzunil I de Electricidad, Limitada (‘‘Orzunil’’), a limited responsibility company incorporated in Guatemala and established for the purpose of generating power by means of a geothermal power plant in the Province of Quetzaltenango in Guatemala. The Company operates and maintains the geothermal power plant and the power purchaser supplies geothermal fluid to the power plant.

On March 13, 2006, the Company acquired a 50.8% ownership interest in Orzunil and increased its then existing 21.0% ownership interest to 71.8%. The purchase price of this acquisition was $15.4 million, including acquisition costs of approximately $0.6 million.

The Company’s 21.0% ownership interest in Orzunil prior to the abovementioned acquisition was accounted for under the equity method of accounting as the Company had the ability to exercise significant influence, but not control, over Orzunil. As a result of the acquisition of the additional 50.8% interest in Orzunil, the financial statements of Orzunil were consolidated with the Company’s financial statements effective March 13, 2006.

On August 16, 2006, the Company completed the acquisition from each of CDC Group plc (‘‘CDC’’) and International Finance Corporation (‘‘IFC’’), both of which are the Zunil Project’s senior lenders, a 14.1% ownership interest in Orzunil (for a total of 28.2%), thereby increasing the Company’s then existing 71.8% ownership interest to 100%. The total purchase price of both acquisitions was $7.4 million, including acquisition costs of approximately $0.9 million.

The abovementioned acquisitions have been accounted for under the purchase method of accounting and the acquired assets are being depreciated over their estimated useful lives of 13.5 years. The purchase prices of all the abovementioned acquisitions ($22.8 million) have been allocated to the fair value of assets and liabilities based on an independent valuation and management’s estimates as follows:

119

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	(dollars in thousands)
Cash and cash equivalents		$	8
Restricted cash			3,408
Accounts receivable assumed			3,176
Property, plant and equipment			42,621
Intangibles (power purchase agreement)			5,250
Accounts payable and other liabilities assumed			(1,241	)
Long-term loans assumed (including current portion)			(23,210	)
			30,012
Less: the Company’s investment prior to acquisition			(7,244	)
Total purchase price allocation		$	22,768

The revenues of Orzunil and the Company’s share in the net income of Orzunil were $10,343,000 and $3,018,000, respectively, for the period from March 13, 2006 to December 31, 2006.

The Company’s equity in income of Orzunil was not significant for each of the years presented in these financial statements.

The Mammoth Project

On December 18, 2003, the Company acquired a 50% interest in the Mammoth Project, which is comprised of three geothermal power plants located near the city of Mammoth, California. The purchase price was less than the underlying net equity of Mammoth by approximately $9.3 million. As such, the basis difference will be amortized over the remaining useful life of the property, plant and equipment and the power purchase agreements, which range from 12 to 17 years. Effective December 18, 2003, the Company operates and maintains the geothermal power plants under an operating and maintenance (‘‘O&M’’) agreement. The Company’s 50% ownership interest in Mammoth is accounted for under the equity method of accounting as the Company has the ability to exercise significant influence, but not control, over Mammoth.

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


	December 31,
	2006			2005
	(dollars in thousands)
Condensed balance sheets:
Current assets		$	3,425		$	7,430
Non-current assets			79,942			82,550
Current liabilities			667			1,114
Non-current liabilities			3,130			3,708
Partners’ Capital			79,570			85,158

120

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Year Ended December 31,
	2006				2005				2004
	(dollars in thousands)
Condensed statements of operations:
Revenues		$	15,339			$	15,782			$	15,815
Gross margin			1,657				4,021				3,830
Net income			1,412				3,824				3,251

Company’s equity in income of Mammoth:
50% of Mammoth net income		$	706			$	1,912			$	1,761
Plus amortization of basis difference			593				593				593
			1,299				2,505				2,354
Less income taxes			(493	)			(952	)			(894	)
Total		$	806			$	1,553			$	1,460

The Mammoth project sells its electrical output to Southern California Edison Company (‘‘SCE’’) under three separate power purchase agreements. Under the G-1 power purchase agreement, in certain circumstances, SCE or its affiliates has a right of first refusal to acquire the plant.

The Leyte Project (‘‘OLCL’’)

The Company holds an 80% interest in OLCL (which owns the Leyte Project); however, as further discussed in Note 1, upon the adoption of FIN No. 46R, the balance sheet of OLCL was deconsolidated as of March 31, 2004, and the income and cash flow statements have been deconsolidated effective April 1, 2004.

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


	December 31,
	2006			2005
	(dollars in thousands)
Condensed balance sheets:
Current assets		$	7,548		$	7,972
Non-current assets			4,632			11,267
Current liabilities			4,782			6,083
Non-current liabilities			—			3,810
Stockholders’ equity			7,398			9,346

121

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Year Ended December 31,						Period from April 1, 2004 to December 31, 2004
	2006			2005			Period from April 1, 2004 to December 31, 2004
	(dollars in thousands)
Condensed statements of operations:
Revenues		$	13,715		$	13,134		$	8,217
Gross margin			6,417			6,246			2,592
Net income			2,787			5,271			838
Company’s equity in income of OLCL:
80% of OLCL net income		$	2,230		$	4,217		$	670
Plus amortization of deferred revenue on intercompany profit ($0.8 million unamortized balance at December 31, 2006)			1,384			708			789
Total		$	3,614		$	4,925		$	1,459

OLCL’s operating results for all periods prior to March 31, 2004 have been accounted for on the consolidated method of accounting, and effective April 1, 2004, the Company’s ownership interest in OLCL is accounted for using the equity method of accounting.

In 1996, OLCL entered into a Build, Operate, and Transfer (‘‘BOT’’) agreement with PNOC-Energy Development Corporation (‘‘PNOC’’) in connection with the four geothermal power generation plants, with a total capacity of 49MW, located in Leyte, Philippines. The BOT agreement calls for OLCL to design, construct, own, and operate geothermal electricity generating plants, utilizing the geothermal resources of the Leyte Geothermal Power Optimization Project Area. During 1997, the power plants started commercial operations and began selling power to PNOC under a ten year power purchase agreement (tolling arrangement). OLCL receives capacity and energy fees from PNOC established by the BOT agreement. Fees are paid each month through the term of the BOT agreement and vary based on plant performance. OLCL owns the plants for a ten-year period ending September 2007, at which time they will be transferred to PNOC for no further consideration. The Company does not anticipate any material financial loss as a result of such transfer, although going forward this will reduce the Company’s foreign generation capacity by 49 MW.

In connection with the construction of the four geothermal power generation plants, OLCL obtained a term loan (‘‘Term Loan’’) amounting to approximately $44.5 million from the Export-Import Bank of the government of the United States (‘‘Eximbank’’). Principal is payable in equal quarterly installments through July 2007. Interest on the Term Loan is at a fixed rate of 6.54% and is payable quarterly. The balance of the Term Loan as of December 31, 2006 and 2005 is $3,810,000 and $8,890,000, respectively. The Term Loan is collateralized by a mortgage on all real property, an assignment of revenues, and the pledge of partnership interests in OLCL. There are various covenants under the Term Loan, which include maintaining minimum levels of equity ratio, as defined, and limitations on additional indebtedness and payment of dividends. As of December 31, 2006, Management believes that OLCL was in compliance with the covenants under the Term Loan.

122

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6 — PROPERTY, PLANT AND EQUIPMENT

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


	December 31,
	2006				2005
	(dollars in thousands)
Land		$	11,503			$	11,521
Leashold improvements			1,114				966
Machinery and equipment			15,401				13,558
Office equipment			3,058				2,840
Automobiles			1,720				1,278
Gethermal and recovered energy generation power plants, including geothermal wells:
United States of America			582,567				471,886
Foreign countries			120,852				68,547
Asset retirement cost			14,078				9,678
			750,293				580,274
Less accumulated depreciation			(126,204	)			(88,439	)
Property, plant and equipment, net		$	624,089			$	491,835

Depreciation expense for the years ended December 31, 2006, 2005 and 2004 amount to $38,659,000, $31,210,000 and $31,729,000, respectively.

U.S. operations:

The net book value of the property, plant and equipment, including construction in process, located in the United States is approximately $636,332,000 and $514,176,000 as of December 31, 2006 and 2005, respectively.

Foreign operations:

During 1998, the Company entered into a power purchase agreement with Kenya Power and Lighting Co. Ltd. (‘‘KPLC’’) , the Kenyan parastatal electricity transmission and distribution company. Under the agreement, the Company agreed to design, construct and operate geothermal power plants in Kenya in several phases. Upon the completion of construction of each phase, KPLC is committed to purchase the electricity generated by the power plants for a minimum of 20 years under the terms of the power purchase agreement. Phase I of the Olkaria III project, which generates 13 MW, has been completed and the net book value of the assets related to the generation power plant and the related wells amounted to approximately $28,813,000 and $30,591,000 at December 31, 2006 and 2005, respectively. As of December 31, 2006 and 2005, the Company had incurred approximately $21,556,000 (included in construction-in-process), in connection with construction of Phase II of the power plant. On January 19, 2007, the Company entered into an Amended and Restated Power Purchase Agreement and a Project Security Agreement, with KPLC with respect to Phase II of Olkaria III project. These agreements were executed after receipt of appropriate regulatory approvals from the Kenyan authorities. The construction of the second phase of the project is expected, upon completion, to add approximately 35 MW to the existing facility, bringing the project’s total capacity to approximately 48 MW. Under the Amended and Restated Power Purchase Agreement, the parties agreed to shorten the construction period for Phase II to approximately twenty-one months commencing from the deposit of agreed collateral by KPLC, which occurred on February 7, 2007 and to reduce the tariff payable by KPLC on the total capacity of the plant upon completion of Phase II. Management believes that the project will be completed in the required timeframe. If the Company does not complete the construction of Phase II by the required date, the Company may lose some or all of its investment in the construction-in-process relating to Phase II.

123

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In June 1999, the Company entered into an agreement with Nicaraguan Electricity Company (‘‘NEC’’), a Nicaraguan power utility, whereby the Company will rehabilitate existing wells, drill new wells, and operate the geothermal facilities. The Company owns the plants for a fifteen-year period ending in 2014, at which time they will be transferred to NEC at no cost. The Company sells the power from the facilities to two power companies who are assignees of NEC at the agreed upon price and terms of the ‘‘take or pay’’ power purchase agreement. The net book value of the assets related to the constructed plant and wells and rehabilitated existing wells amounted to approximately $21,019,000 and $21,060,000 at December 31, 2006 and 2005, respectively. Additionally, as of December 31, 2005, the Company has incurred approximately $1,215,000 (included in construction-in-process) to drill an additional well.

As described in Note 5, during 2006, the Company increased its share in Orzunil from 21% to 100% through acquisitions. In December 1993, Orzunil entered into a twenty-year power purchase agreement (‘‘PPA’’) with Instituto Nacional de Elecrification (‘‘INDE’’). The Zunil project is located in Zunil, Guatemala. The Zunil project is comprised of one plant which commenced commercial operations in 1999 and has a generating capacity of 24 MW. According to the PPA, the geothermal resources used by the power plant are owned by INDE, which only 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 amounted to approximately $40,258,000 at December 31, 2006.

The Company is engaged in the construction of several geothermal power plants in other foreign countries. At December 31, 2006 and 2005, such projects were in the various stages of construction and the related costs totaling approximately $36,368,000 and $22,367,000, respectively, are included in construction-in-process.

NOTE 7 — INTANGIBLE ASSETS

Intangible assets consist mainly of all of the Company’s power purchase agreements acquired in business combinations and amounted to $50,086,000 (including royalty rights in the amount of $1,800,000) and $47,915,000 (including royalty rights in the amount of $1,800,000), net of accumulated amortization of $9,327,000 and $6,248,000 as of December 31, 2006 and 2005, respectively. Amortization expense for the years ended December 31, 2006, 2005 and 2004 amount to $3,079,000, $2,815,000 and $2,523,000, respectively.

Estimated future amortization expense for the intangible assets as of December 31, 2006 is as follows:


Year ending December 31:	(dollars in thousands)
2007		$	3,097
2008			3,053
2009			3,053
2010			3,053
2011			3,053
Thereafter			34,777
Total		$	50,086

124

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8 — ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses consist of the following:


	December 31,
	2006			2005
	(dollars in thousands)
Trade payables		$	38,524		$	32,641
Scheduling and transmission charges			841			1,192
Royalties			595			1,143
Salaries and other payroll costs			6,514			6,186
Accrued interest			12,860			883
VAT payable			869			471
Income tax payable			5,215			4,352
Other			5,027			3,180
Total		$	70,445		$	50,048

NOTE 9 — LONG-TERM DEBT

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


	December 31,
	2006				2005
	(dollars in thousands)
Limited and non-recourse agreements:
Non-recourse agreement:
Senior loans:
International Finance Corporation Loan A		$	6,973			$	—
International Finance Corporation Loan B			3,883				—
Commonwealth Development Corporation Loan			8,530				—
Limited recourse agreement:
Credit facility agreement			11,253				14,140
			30,639				14,140
Less current portion			(8,482	)			(2,888	)
Total		$	22,157			$	11,252
Full recourse agreements with a bank		$	2,000			$	3,000
Less current portion			(1,000	)			(1,000	)
Total		$	1,000			$	2,000
Senior Secured Notes (non recourse):
Ormat Funding Corp. (‘‘OFC’’)		$	178,693			$	183,399
OrCal Geothermal Inc. (‘‘OrCal’’)			160,677				165,000
			339,370				348,399
Less current portion			(40,054	)			(23,754	)
Total		$	299,316			$	324,645

125

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Senior Loans

International Finance Corporation (‘‘IFC’’) Loan A

Orzunil, a wholly owned subsidiary of the Company, has a senior loan agreement with IFC, which was a minority shareholder of Orzunil (see also Note 5). The loan matures on November 15, 2011, and is payable in 47 quarterly installments ranging from $192,000 to $430,000. The loan has a fixed annual interest rate of 11.775%.

International Finance Corporation (‘‘IFC’’) Loan B

Orzunil has another senior loan agreement with IFC. The loan matures on May 15, 2008, and is payable in 32 quarterly installments ranging from $436,000 to $690,000. The loan has a fixed annual interest rate of 11.730%.

Commonwealth Development Corporation (‘‘CDC’’) Loan

Orzunil has a senior loan agreement with CDC, which was also a minority shareholder of Orzunil (see also Note 5). The loan matures on August 15, 2010, and is payable in 42 quarterly installments ranging from $348,000 to $675,000. The loan has a fixed annual interest rate of 10.300%.

There are various restrictive covenants under these Senior Loans, which include limitations on Orzunil’s ability to make distributions to its shareholders. Due to hurricane activity, access roads and piping from the wells to the power plant in the Zunil Project were damaged and, consequently, the Project was not in operation from October 14, 2005 to March 10, 2006. As a result, Orzunil did not meet the historical ‘‘debt service coverage ratio’’ required and therefore, at present, distributions from the Project are restricted. As of December 31, 2006, management believes that Orzunil is in compliance with the required debt service coverage ratio and with all other covenants.

Credit Facility Agreement (the Momotombo Project)

In September 2000, Ormat Momotombo Power Company (‘‘OMPC’’), a wholly owned subsidiary of the Company, entered into a credit facility agreement with Bank Hapoalim B.M. pursuant to which OMPC executed a two-phase loan with the bank in the amounts of $11,435,000 (‘‘Phase I Loan’’) and $36,800,000 (‘‘Phase II Loan’’) (collectively the ‘‘Credit Facility Agreement’’). In March 2003, OMPC signed an amendment to the Credit Facility Agreement changing the amount of the Phase II Loan from $36,800,000 to $15,000,000. Principal and interest payments on the Phase I Loan are payable in 32 equal quarterly payments that commenced upon completion of Phase I of the project in December 2001. Interest on the Phase I Loan is variable based on 3-month LIBOR plus 2.375%. Principal and interest payments on the Phase II Loan are payable in equal 28 quarterly payments that commenced in March 2004. Interest on the Phase II Loan is variable based on 3-month LIBOR plus 3.0%, and is added to the outstanding balances of the Phase II Loan until the commencement of the principal and interest payments. At December 31, 2006 and 2005, $4,476,000 and $5,666,000, respectively, was outstanding under the Phase I Loan and $6,777,000 and $8,474,000, respectively, was outstanding under the Phase II Loan. The Credit Facility Agreement is collateralized by liens over all real and personal property comprising the Momotombo Project and the Company’s ownership interest in OMPC. There are various restrictive covenants under the Credit Facility Agreement, which include maintaining certain levels of debt to equity ratio and debt service coverage ratio, and limitations on additional indebtedness and payment of dividends. As of December 31, 2006, management believes that OMPC was in compliance with the covenants under the Credit Facility Agreement.

Full Recourse Agreements with a Bank

The Company has an $8.0 million loan agreement, with principal payable in $1 million annual installments that commenced in May 2001 and continue through May 2008. Interest is computed at 12-month LIBOR plus 1.7%, and is payable annually.

126

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Future minimum payments

Future minimum payments under long-term obligations, excluding the senior secured notes and notes payable to Parent, as of December 31, 2006 are as follows:


Year ending December 31:	(dollars in thousands)
2007		$	9,482
2008			8,667
2009			6,676
2010			6,101
2011			1,713
Total		$	32,639

OFC Senior Secured Notes

On February 13, 2004, OFC, a wholly owned subsidiary, completed the issuance of $190.0 million, 8¼% Senior Secured Notes (the ‘‘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 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. On June 30, 2006 and December 31, 2006, OFC did not meet the ‘‘debt service coverage ratio’’ and, therefore, it is restricted from payment of dividends until it meets such ratio.

The Company has not yet granted a security interest over the new unit of the Desert Peak 2 project to the OFC Senior Secured Noteholders which is required under the indenture for the OFC Senior Secured Notes. The Company is evaluating an alternative approach to replacing the Desert Peak 1 plant with one of the new units of the Desert Peak 2 project. Implementing such an alternative would require the consent of the OFC Senior Secured Noteholders in order to ensure continued compliance with the covenants of the indenture governing the OFC Senior Secured Notes. The Company expects to launch a consent solicitation in order to amend and/or waive certain provisions of the indenture to obtain such consent from the OFC Senior Secured Noteholders. Any such solicitation will be made by means of and subject to appropriate documentation and only to the OFC Senior Secured Noteholders.

Management believes that except as described above, as of December 31, 2006, OFC is in compliance with all other 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.

A registration statement on Form S-4 relating to the OFC Senior Secured Notes was filed with and declared effective by the SEC on February 9, 2005. Pursuant to the registration statement, OFC

127

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

made an offer to the holders of the OFC Senior Secured Notes to exchange them for publicly registered exchange notes with substantially identical terms until March 11, 2005. On March 16, 2005 the exchange offer was completed.

On April 26, 2006, OFC successfully consummated a consent solicitation relating to the OFC Senior Secured Notes that was launched on April 17, 2006. On that same date, OFC executed a supplement to the indenture governing the OFC Senior Secured Notes to amend and/ or waive certain provisions in the indenture dealing with public reporting and information requirements of OFC. On May 1, 2006, OFC filed with the SEC Form 15 notification of the suspension of its obligation to file reports with the SEC under the Securities Act of 1934.

Debt service reserve

As required under the terms of the OFC Senior Secured Notes, OFC maintains an account, which may be funded by cash or backed by letters of credit (see below) in an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the OFC Senior Secured Notes in the following six months. This restricted cash account is classified as current on the balance sheet. As of December 31, 2006 and 2005, the balance of such account was $13.3 million and $12.3 million, respectively. In addition, as of December 31, 2006, part of the restricted cash accounts was funded by two letters of credit in the total amount of approximately $12.2 million (see Note 18).

Future minimum payments under the OFC Senior Secured Notes, as of December 31, 2006 are as follows:


Year ending December 31:	(dollars in thousands)
2007		$	13,836
2008			7,835
2009			9,140
2010			10,118
2011			11,410
Thereafter			126,354
Total		$	178,693

OrCal Senior Secured Notes

On December 8, 2005, OrCal, a wholly owned subsidiary, completed the issuance of $165.0 million, 6.21% Senior Secured Notes (the ‘‘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 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, 2006, 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

128

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

plus accrued interest, and a ‘‘make-whole’’ premium. Upon certain events, as defined in the indenture governing the OrCal Senior Secured Notes, OrCal may be required to redeem a portion of the OrCal Senior Secured Notes at a redemption price of 100% of the principal amount of the OrCal Senior Secured Notes being redeemed plus accrued interest.

Debt service reserve

As required under the terms of the OrCal Senior Secured Notes, OrCal maintains an account, with a required minimum balance, 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 OrCal Senior Secured Notes in the following six months. This restricted cash account is classified as current on the balance sheet. As of December 31, 2006 and 2005, the balance of such account was $14.8 million and $9.5 million, respectively. In addition, as of December 31, 2006, part of the restricted cash accounts was funded by a letter of credit in the amount of approximately $9.7 million (see Note 18).

Future minimum payments under the OrCal Senior Secured Notes, as of December 31, 2006 are as follows:


Year ending December 31:	(dollars in thousands)
2007		$	26,218
2008			17,641
2009			11,043
2010			10,216
2011			9,700
Thereafter			85,859
Total		$	160,677

In anticipation of the OrCal Offering, on September 9, 2005, the Company entered into a rate lock agreement with a financial institution (the ‘‘counterparty’’), at a locked-in rate of 4.047%, with a notional amount of $175.0 million, which terminated on December 5, 2005. The rate lock was based on a 7-year treasury security that matures in November 2012. On December 5, 2005, the Company received from the counterparty to the rate lock agreement an amount of $4,488,000. A gain of $2,624,000, net of related taxes of $1,608,000, is recorded as ‘‘Gain in respect of derivative instruments designated for cash flow hedge, net of related taxes’’ under ‘‘Other comprehensive income (loss)’’ and is amortized over the term of the OrCal Senior Secured Notes using the effective interest method. The remaining gain of $159,000, net of related taxes of $97,000, has been charged to the consolidated statement of operations ($256,000 has been recorded as interest income and $97,000 has been recorded as income tax expense).

In December 2003, in connection with the acquisition of the Heber power plants, OrCal entered into a loan agreement with Beal Bank (‘‘Beal Bank Credit Agreement’’) to provide a loan in the amount of $154.5 million. On December 8, 2005, in connection with the issuance of the OrCal Senior Secured Notes, OrCal repaid the loan in its entirety. This repayment resulted in a one-time charge to interest expense of approximately $16.6 million, comprised of: (i) prepayment premium of $11.5 million associated with payment of the Beal Bank loan, (ii) write-off of certain deferred financing costs amounting to $4.2 million associated with the incurrence of the Beal Bank loan, and (iii) loss of $0.9 million associated with the interest rate caps transaction described below. The tax effect of such one time charge is $6.3 million, bringing the net effect of it to $10.3 million.

During the second quarter of 2004, the Company entered into two separate interest rate cap agreements (‘‘Cap Transactions’’) with two different financial institutions to mitigate the interest rate

129

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

risk associated with the Beal Bank Credit Agreement. Pursuant to the Cap Transactions, the Company paid an aggregate of $3,820,000 to the financial institutions. The Cap Transactions are effective as of March 30, 2007 and terminate on March 31, 2011. Pursuant to the terms of the Cap Transactions, the financial institutions providing the cap are required to pay to the Company the difference between the 3-month LIBOR rate and 6.0%, (if LIBOR is greater than 6.0%), times the notional amount, which for each of the contracts will be $67,401,000 on the effective date and reduces each payment period down to $49,633,000 upon termination. From October 1, 2004 to December 8, 2005 (the date of the repayment of the Beal Bank Loan), the Cap Transactions qualified for cash flow hedge accounting. The fair value of the Cap Transactions at December 31, 2005 and 2004 amounted to $1,034,000 and $1,663,000, respectively. The decrease in the fair value for the period from the initiation of the Cap Transactions through September 30, 2004 of $1,637,000 has been recorded in the consolidated statement of operations as interest expense, while the decrease in the fair value for the period from October 1, 2004 to December 31, 2004 of $322,000, net of related taxes of $198,000 was included as ‘‘Loss in respect of derivatives instruments designated for cash flow hedge, net of related taxes’’ under ‘‘Other comprehensive income (loss)’’. The decrease in the fair value for the period from January 1, 2005 to December 8, 2005 (the date of the repayment of the Beal Bank loan) of $241,000, net of related taxes of $149,000, was included in ‘‘Other comprehensive income (loss)’’. As a result of the early repayment of the Beal Bank loan, the aggregate amount of $563,000, net of related taxes of $347,000, which was included in ‘‘Other comprehensive income (loss)’’, has been charged to the consolidated statement of operations ($910,000 have been recorded as interest expense and $347,000 have been recorded as income tax benefit), and the decrease in the fair value for the period from December 8, 2005 to December 31,2005 of $239,000 has been recorded in the consolidated statement of operations as interest expense. The decrease in the fair value for the year ended December 31, 2006 of $559,000 has been recorded in the consolidated statement of operations as interest expense. The fair value of the Cap Transactions is the estimated amount that the Company would currently pay to terminate the transactions at the reporting date, taking into account current interest rates and the current creditworthiness of the counterparties to the agreements.

NOTE 10 — PUNA PROJECT LEASE TRANSACTIONS

On May 19, 2005, the Company’s wholly owned subsidiary in Hawaii, Puna Geothermal Ventures (‘‘PGV’’) entered into a transaction involving the Puna geothermal power plant located on the Big Island of Hawaii (the ‘‘Puna Project’’), which was acquired in June 2004. A similar 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 (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, 2006 and 2005 amounted to $56.0 million and $58.3 million, net of accumulated depreciation of $6.4 million and $3.7 million, respectively. The unrelated company (the ‘‘Lessor’’) simultaneously leased back the Puna Project 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 Project under a power purchase agreement 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 power purchase agreement 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 SFAS No. 13, Accounting 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 $4.3 million are being amortized, using the straight-line method, over the 23-year term of the Project Lease.

130

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Future minimum lease payments under the Project Lease, as of December 31, 2006, are as follows:


Year ending December 31:	(dollars in thousands)
2007		$	9,742
2008			7,573
2009			8,013
2010			7,567
2011			8,061
Thereafter			72,126
Total		$	113,082

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 are included in the balance sheet as of December 31, 2006 and 2005 in restricted cash accounts and are classified as current as they are used for current payments.

Revenue account

PGV deposits all revenues received into the revenue account. Such amounts are used to pay operating expenses and fund the depository accounts as describe below, but the funds are only available to PGV upon submission of draw requests by PGV to the bank. As such amounts are fully restricted to use by PGV, they have been classified as current restricted assets as the amounts are used to pay current operating expenses. As of December 31, 2006 and 2005, the balance of such account was $2.7 million and $3.5 million, respectively.

Lease rent reserve accounts

PGV maintains accounts to fund the full amount of the next rent payment according to the payment schedule. As of December 31, 2006 and 2005, the balance of such accounts was $6.2 million and $2.3 million, respectively.

Well maintenance reserve account

PGV maintains a reserve account to fund well field works including the drilling of new wells. The reserve should be met on a monthly basis, in amounts equal to 1/12 of a scheduled annual contribution. As of December 31, 2006 and 2005, the balance of such account was $0.2 million and $0.5 million, respectively.

Capital expenditure account

PGV maintains an account to fund its capital expenditures. Deposits to this account are at PGV’s sole discretion, but no distributions are allowed to Ormat Nevada Inc., a wholly owned subsidiary of the Company that is the indirect parent of PGV, if the balance is less than $0.5 million. As of December 31, 2006 and 2005, the balance in this account was $0.5 million and $0, respectively.

Distribution account

PGV maintains an account to deposit its remaining cash, after making all of the necessary payments and transfers as provided for in the lease agreements, in order to make distributions to Ormat Nevada Inc. The distributions are allowed only if PGV maintains various restrictive covenants

131

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

under the lease agreements, which include limitations on additional indebtedness. As of December 31, 2006 and 2005, the balance of such account was $11.3 million and $6.8 million, respectively. This amount can be distributed to Ormat Nevada Inc. currently and has been classified as current restricted assets.

In anticipation of the above lease transactions, on February 25, 2005, the Company entered into a treasury rate lock agreement with a financial institution, at a locked-in treasury rate of 4.31%, with a notional amount of $52.0 million, which terminated on March 31, 2005. The rate lock was based on a 10-year treasury security that matures on February 15, 2015. On March 31, 2005, the Company received from the counterparty to the rate lock agreement an amount of $658,000. This amount, net of related taxes of $250,000, is recorded as ‘‘Gain in respect of derivative instruments designated for cash flow hedge, net of related taxes’’ under ‘‘Other comprehensive income (loss)’’ and is amortized over the 23-year term of the Project Lease.

On April 20, 2005, the Company entered into a new treasury rate lock agreement with the same financial institution, at a locked-in treasury rate of 4.22%, with a notional amount of $52.0 million and originally scheduled to terminate on May 2, 2005. The new rate lock agreement’s termination date was extended until May 18, 2005 at a new locked-in treasury rate of 4.25%. The rate lock was based on a 10-year treasury security that matures on February 15, 2015. There was no consideration paid by either party as a result of the extension. On May 18, 2005, the Company paid the counterparty to the new rate lock agreement the amount of $762,000. This amount, net of related taxes of $290,000, is recorded in ‘‘Other comprehensive income (loss)’’ and is amortized over the 23-year term of the Project Lease.

NOTE 11 — ASSET RETIREMENT OBLIGATION

The following table presents a reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligation for the years presented below:


	December 31,
	2006			2005
	(dollars in thousands)
Balance at beginning of period		$	11,461		$	10,665
Changes in price estimates			4,400			22
Accretion expense			971			774
Balance at end of period		$	16,832		$	11,461

During the fourth quarters of 2006 and 2005, the Company increased the aggregate carrying amount of its asset retirement obligation by $4,400,000 and $22,000, respectively. The net increase is a result of increased costs associated with drilling rigs, cement and cement services, general manpower, engineering fees and other outside services since the adoption of SFAS No. 143.

132

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12 — STOCK-BASED COMPENSATION

Effective January 1, 2006, the Company adopted SFAS No. 123R which establishes the accounting for employee stock-based awards. Under the provisions of SFAS No. 123R, stock-based compensation 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 adopted SFAS No. 123R using the modified prospective method. Under this method, prior periods are not restated and the amount of compensation cost recognized includes (i) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123, Accounting for Stock-Based Compensation, and (ii) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123R. SFAS No. 123R requires unrecognized cost, based on the amounts previously disclosed in the Company’s pro forma footnote disclosure, related to options vesting after the date of initial adoption to be recognized in the financial statements over the remaining requisite service period. The provisions of SFAS No. 123R apply to new stock awards and stock awards outstanding, but not yet vested, on the effective date. In March 2005, the SEC issued Staff Accounting Bulletin No. 107 (‘‘SAB No. 107’’) relating to SFAS No. 123R. The Company has applied the provisions of SAB No. 107 in its adoption.

Impact of the adoption of SFAS No. 123R

Upon adoption of SFAS No. 123R, the Company recognizes share-based compensation expenses associated with share awards on a straight-line basis over the requisite service period using the fair value method. The incremental share-based compensation expense recognized due to the adoption of SFAS 123R was $1.7 million for the year ended December 31, 2006.

As required by SFAS No. 123R, the Company made an estimate of expected forfeitures and is recognizing compensation costs only for those equity awards expected to vest. The cumulative effect of initially adopting SFAS No. 123R is not material. As of December 31, 2006, the total future compensation cost related to unvested stock options that are expected to vest is $4,023,503 which will be recognized over a weighted average period of 2.94 years.

During the year ended December 31, 2006 the Company recorded stock-based compensation related to stock options as follows:


	(In thousands, except per share data)
Cost of Revenues		$	798
Selling and marketing expenses			287
General and administrative expenses			621
Total stock-based compensation expense			1,706
Tax effect on stock-based compensation expense			239
Net effect on stock-based compensation expense		$	1,467
Effect on basic and diluted earnings per share		$	0.04

Pro forma information for periods prior to the adoption of SFAS No. 123R

Prior to January 1, 2006, the Company accounted for stock-based compensation in accordance with the provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (‘‘ APB No. 25’’), and related interpretations. Under APB No. 25, compensation cost was

133

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

recognized based on the difference, if any, on the date of grant between the fair value of the Company’s stock and the amount an employee must pay to acquire the stock.

SFAS No. 123R requires disclosure of pro forma information for periods prior to the adoption. The pro forma disclosures are based on the fair value of awards at the grant date, amortized to expense over the service period. The following table illustrates the effect on net income and earnings per share as if the Company had applied the fair value recognition provisions of SFAS No. 123 for the period prior to the adoption of SFAS No. 123R and the actual effect on net income and earnings per share for the period after the adoption of SFAS No. 123R.


	Year ended December 31,
	2006				2005				2004
	(dollars in thousands, except per share data)
Net income, as reported		$	34,447			$	15,177			$	17,791
Add: Total stock-based employee compensation expense included in reported net income, net of tax			1,467				91				61
Deduct: Total stock-based employee compensation expense in respect of the Company’s stock options determined under fair value based method, net of tax			(1,166	)			(65	)			(6	)
Deduct: Total stock-based employee compensation expense in respect of the Parent’s stock options determined under fair value based method, net of tax			(301	)			(307	)			(685	)
Pro forma net income		$	34,447			$	14,896			$	17,161
Earnings per share:
Basic, as reported		$	1.00			$	0.48			$	0.72
Basic, pro forma		$	1.00			$	0.47			$	0.69
Diluted, as reported		$	0.99			$	0.48			$	0.72
Diluted, pro forma		$	0.99			$	0.47			$	0.69

The fair value of each option grant 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’’ defined in SAB No. 107, giving consideration to the contractual term and vesting schedule. Since the Company does not have any traded stock options 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 0.55% yearly dividend rate. The risk free interest rate was based on the yield from U.S. constant treasury maturities bonds with an equivalent term. The forfeiture rate of 5% is based on trends in actual option forfeitures.

134

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company calculated the fair value of each option on the date of grant based on the following assumptions:


	Year Ended December 31,
	2006			2005			2004
For stock options issued by the Company:
Risk-free interest rates		4.9	%		4.5	%		3.6	%
Expected lives (in years)		6.4			5.0			5.0
Dividend yield		0.55	%		0.9	%		4.0	%
Expected volatility		40.5	%		32.0	%		40.0	%
Forfeiture rate		5.0	%		—			—
For stock options issued by the Parent:
Risk-free interest rates		—			—			4.7	%
Expected lives (in years)		—			—			5.0
Dividend yield		—			—			0	%
Expected volatility		—			—			28	%

Stock Option Plans

The 2004 Incentive Compensation Plan

On October 21, 2004, the Company’s Board of Directors adopted the 2004 Incentive Compensation Plan (‘‘2004 Incentive Plan’’), which provides for the grant of the following types of awards: incentive stock options, non-qualified stock options, restricted stock, stock appreciation rights, 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 1,250,000 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 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 day. Vested shares may be exercised for up to ten years from the date of grant. On November 9, 2005, the Company filed a registration statement on Form S-8 with the SEC with respect to the shares of common stock underlying such grants. The shares of common stock will be issued upon exercise of options from the Company’s authorized share capital.

135

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On February 27, 2006 the Company’s Board of Directors approved an increase of the total number of shares of the Company’s common stock which have been reserved for issuance to 3,750,000, subject to stockholder approval. The following table summarizes the status of the 2004 Incentive Plan as of and for the periods presented below (shares in thousands):


	Year Ended December 31, 2006						Year Ended December 31, 2005						Year Ended December 31, 2004
	Shares			Weighted Average Exercise Price			Shares			Weighted Average Exercise Price			Shares		Weighted Average Exercise Price
Outstanding at beginning of year		236			$	15.54		223			$	15.00		—		$	—
Granted, at fair value		329				34.47		25				20.10		223			15.00
Exercised		(14	)			15.00		—				—		—			—
Forfeited		(12	)			20.25		(12	)			15.00		—			—
Outstanding at end of year		539				27.03		236				15.54		223			15.00
Options exercisable at end of year		72				16.76		15				15.00		—
Weighted-average fair value of options granted during the year					$	15.77					$	6.62				$	0.96

As of December 31, 2006, 696,900 shares of the Company’s common stock are available for future grants.

The following table summarizes information about stock options outstanding at December 31, 2006 (shares in thousands):


	Options Outstanding							Options Exercisable
Exercise Price	Number of Shares Outstanding		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value (In thousands)			Number of Shares Exerciseble		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value (In thousands)
$15.00		188		7.8		$	4,094		47		7.8		$	1,035
20.10		25		7.8			418		25		7.8			418
34.13		296		9.3			797		—		—			—
37.90		30		6.8			—		—		—			—
		539		8.6		$	5,309		72		7.8		$	1,453

The following table summarizes information about stock options outstanding at December 31, 2005 (shares in thousands):


	Options Outstanding							Options Exercisable
Exercise Price	Number of Shares Outstanding		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value (In thousands)			Number of Shares Exerciseble		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value (In thousands)
$15.00		211		8.8		$	2,348		15		8.8		$	167
20.10		25		8.8			151		—		—			—
		236		8.8		$	2,499		15		8.8		$	167

The aggregate intrinsic value in the above tables represents the total pretax intrinsic value, based on the Company’s stock price of $36.82 as of December 31, 2006, which would have potentially been

136

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

received by the option holders had all option holders exercised their options as of that date. The total number of in-the-money options exercisable as of December 31, 2006 was 72,426.

The total pretax intrinsic value of options exercised during the year ended December 31, 2006 was $331,000 based on the Company’s average stock price of $38.12 during the year ended December 31, 2006.

The Parent’s Stock Option Plans

The Parent has four stock option plans: the 2001 Employee Stock Option Plan, the 2002 Employee Stock Option Plan, the 2003 Employee Stock Option Plan, and the 2004 Employee Stock Option Plan (collectively ‘‘the Parent’s Plans’’). Options under the 2004 Employee Stock Option Plan were granted in April 2004. Under the Parent’s 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. Options under the Parent’s Plans 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. Vested shares may be exercised for up to five years from the date of grant. The maximum aggregate number of shares that may be optioned and sold under the Parent’s Plans is determined each year by the board of directors of the Parent, and is equal to the number of options granted during each plan year. None of the options are exercisable or convertible into shares of the Company.

As of December 31, 2006, no shares of the Parent’s ordinary shares are available for future grants.

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, 2006						Year Ended December 31, 2005						Year Ended December 31, 2004
	Shares			Weighted Average Exercise Price			Shares			Weighted Average Exercise Price			Shares			Weighted Average Exercise Price
Outstanding at beginning of year		1,747			$	2.42		2,362			$	2.32		1,930			$	1.81
Granted, below fair value		—				—		—				—		651				3.78
Exercised		(560	)			1.81		(554	)			1.97		(192	)			1.97
Expired		(32	)			2.26		—				—		—				—
Forfeited		(57	)			2.96		(61	)			2.62		(27	)			2.00
Outstanding at end of year		1,098				2.70		1,747				2.42		2,362				2.32
Options exercisable at end of year		322			$	2.23		296				1.79		215				1.88
Weighted-average fair value of options granted during the year					$	—					$	—					$	1.73

The Company recorded in the year ended December 31, 2004, deferred stock compensation of $52,000 for options granted below fair market value. This balance represents the difference between the exercise price of the options and the fair market value of the Parent’s shares on the date of grant. Prior to January 1, 2006, the deferred stock compensation has been amortized to expense over the vesting period. The amortization of deferred stock compensation for the years ended December 31, 2005 and 2004 is $91,000 and $61,000, respectively.

137

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about stock options outstanding at December 31, 2006 (shares in thousands):


	Options Outstanding							Options Exercisable
Exercise Price	Number of Shares Outstanding		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value (In thousands)			Number of Shares Exerciseble		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value (In thousands)
$1.41		111		0.2		$	1,105		111		0.2		$	1,105
1.75		453		1.2			4,357		116		1.2			1,118
3.78		534		2.3			4,056		95		2.3			721
		1,098		1.6		$	9,518		322		1.2		$	2,944

The following table summarizes information about stock options outstanding at December 31, 2005 (shares in thousands):


	Options Outstanding							Options Exercisable
Exercise Price	Number of Shares Outstanding		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value (In thousands)			Number of Shares Exerciseble		Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value (In thousands)
$1.41		379		1.2		$	2,282		67		1.2		$	405
1.75		681		2.2			3,864		161		2.2			915
2.26		68		0.1			349		68		0.1			349
3.78		619		3.3			2,257		—		—			—
		1,747		2.3		$	8,752		296		1.5		$	1,669

The aggregate intrinsic value in the above tables represents the total pretax intrinsic value, based on the Parent’s stock price of $11.37 as of December 31, 2006, which would have potentially been received by the option holders had all option holders exercised their options as of that date. The total number of in-the-money options exercisable as of December 31, 2006 was 322,179.

The total pretax intrinsic value of options exercised during the year ended December 31, 2006 was $4,328,000 based on the Parent’s average stock price of $9.48 during the year ended December 31, 2006.

138

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 13 — POWER PURCHASE AGREEMENTS

U.S. operations:

The Company has various power purchase agreements in the U.S. as follows:

Southern California Edison Company (‘‘SCE’’) — California

The Company has two power purchase agreements (‘‘PPAs’’) with SCE related to the Ormesa Complex and two PPAs related to the Heber 1 and 2 projects. The PPAs provide for the sale of capacity and energy through their respective terms, with the following expiration dates: Ormesa PPAs expire in 2017 and 2018, and Heber 1 and 2 PPAs expire in 2015 and 2023, respectively. Under the PPAs, the Company receives a fixed energy payment through April 30, 2012, and thereafter an energy payment based on SCE’s short-run avoided cost (‘‘SRAC’’). The PPAs provide for firm capacity and bonus payments established by the contracts and are paid to the Company each month through the contracts’ term based on plant performance. Bonus capacity payments are earned based on actual capacity available during certain peak hours. In certain circumstances, SCE or its designee has a right of first refusal to acquire the OG I and OG II power plants in the Ormesa project and the Heber 1 power plant at fair market value. Upon satisfaction of certain conditions specified in the PPA and subject to receipt of requisite approvals and negotiations between the parties, the Company will have the right to demand that SCE purchase the Heber 1 power plant at fair market value.

In connection with the power purchase agreements for the Ormesa project, SCE has expressed its intent not to pay the contract rate for the power supplied by the GEM 2 and GEM 3 plants to the Ormesa project. SCE contends that California ISO real-time prices should apply, while management believes that SP-15 prices quoted by NYMEX should apply. According to SCE’s estimation, the amount under dispute is approximately $2.5 million. The parties have signed an Interim Agreement; whereby SCE will continue to procure the GEM 2 and GEM 3 power at the current energy rate of 5.37 cents/kWh until May 1, 2007. In addition a long-term PPA is expected to be entered into for the GEM 2 and GEM 3 power. The negotiations of the long-term PPA are still under way and there is no guarantee that it will be successfully completed. Management believes that such settlement agreement will not have a material financial impact on the Company. Therefore, no provision is included in the financial statements in respect of the dispute.

Sierra Pacific Power Company (‘‘SPPC’’) — Nevada

The Company has seven PPAs with SPPC for operating projects; one related to the Brady power plant, two related to the Steamboat 1 and 1A power plants, one related to the Steamboat Hills power plant, two related to the Steamboat 2 and 3 power plants and one related to the Burdette power plant. The Burdette PPA provides for the sale of energy and will expire in 2026. All the other PPAs provide for the sale of energy, and for capacity for all power plants except Brady, through their respective terms, with the following expiration dates: Steamboat 1 and 1A expire in 2007 (see below) and 2018, Steamboat Hills expires in 2018, and Brady and Steamboat 2 and 3 expire in 2022. Energy payments under the Brady PPA are based on deliveries during specified winter and summer seasons for on-peak, mid-peak, and off-peak times. Energy payments under the Steamboat 1/1A PPAs are based on the monthly average of the California-Oregon Border power market pricing, which is SPPC’s adopted SRAC. The Steamboat 1 PPA expired at the end of 2006, but the Company continues to sell electricity by an automatic extension of the PPA on a year-by-year basis.

Hawaii Electric Light Company (‘‘HELCO’’) — Hawaii

The Company has a PPA with HELCO related to the Puna project. The PPA provides for monthly energy payments and capacity payments. The energy payments for a portion of the energy delivered are equal to the higher of the SRAC rates for energy in effect for the relevant billing period

139

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

or a fixed rate. The energy payments for a smaller portion of energy to be delivered are equal to an amount based on a fuel rate and a variable operation and maintenance rate, as each are adjusted over the term of the agreement, but which rate will never go below a minimum floor. The Puna project also receives a payment for providing reactive power to HELCO.

Southern California Public Power Authority (‘‘SCPPA’’) — California

The Company has a 25-year PPA with SCPPA for the sale of energy from the Gould plant in the Heber complex. Under the Gould PPA, 10 MW of power will be delivered to SCPPA for a fixed price which will escalate annually at a rate of 1.5% and includes the value for the environmental attributes, known as renewable energy credits. Deliveries began in the second quarter of 2006.

Nevada Power Company (‘‘Nevada Power’’) — Nevada

The Company has a 25-year PPA with Nevada Power for the sale of energy from the Desert Peak 2 project for a fixed price. Commercial operation of the Desert Peak 2 project has not yet been declared.

Foreign operations:

The Company has power purchase agreements in various foreign countries as follows:

The Olkaria III Project (Kenya)

In connection with the agreement with KPLC (see Note 6), the subsidiary in Kenya, sells power to KPLC at the agreed upon price and terms of a 20-year PPA. Fees are paid each month through the term of the agreement and vary based on plant performance.

The Momotombo Project (Nicaragua)

In connection with the agreement with NEC (see Note 6), the subsidiary in Nicaragua sells power to two assignees of NEC at the agreed upon price and terms of a ‘‘take or pay’’ PPA. Fees are paid each month through the term of the PPA and vary based on plant performance.

The Zunil Project (Guatemala)

In connection with the agreement with INDE (see Note 6), the subsidiary in Guatemala sells power to INDE at the agreed upon price and terms of a 20-year ‘‘take or pay’’ PPA. The PPA provides for monthly minimum energy payments and capacity payments, based on demonstrated capacity. Fees are paid each month through the term of the PPA.

Additional information

Pursuant to the terms of certain of the power purchase agreements, 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 threshold performance 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.

The Brady and Steamboat 2 and 3 PPAs provide that if the project does not maintain peak period capacity values of at least 85% of those listed in each of their respective contracts, the Company will be obligated to pay liquidated damages to SPPC in amounts ranging from $1.0 million to $1.5 million.

140

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

If the Ormesa and Heber 1 and 2 projects fail to meet minimum performance requirements, as defined, the respective project may be placed on probation, the capacity of the relevant plant may be permanently reduced and, in such an instance, a refund would be owed from such project to SCE. Each of the projects may also reduce the capacity of the plants upon notice to SCE and after making a specified payment to it. During 2006, the Company experienced a relatively high rate of well and pump failure at the Ormesa project resulting in a lower availability of the Ormesa well field. As a result, the Ormesa project did not meet the required minimum capacity factor of 80% during the on-peak period for the month of September 2006. Consequently, the Ormesa project has been placed on probation for a period not to exceed 15 months. During the probation period, if the Ormesa project fails again to meet the minimum performance requirements, the capacity of the project may be permanently reduced, in which case SCE would be entitled to a refund. Management believes that the risk of not meeting the requirements during the probation period and in the future is very low.

If the Puna project does not meet its minimum capacity performance requirement, such project will be required to pay HELCO $0.0214 per on-peak hour for each kilowatt of deficiency for the first 5 MW of deficiency and $0.0339 per on-peak hour for each kilowatt of deficiency in excess of 5 MW of deficiency. In addition, for each contract year in which the on-peak availability of the facility is less than 95%, unless the deficiency is due to a catastrophic equipment failure, the Puna project is required to pay $8,000 to HELCO for each full percentage point of the deficiency, and if such availability is less than 80%, the Puna project is required to pay $12,000 for each full percentage point of the deficiency.

The Company has not and does not currently expect to be obligated to make any material payments under its power purchase agreements.

As required by EITF Issue No. 01-8 (see Note 1), the Company assessed all PPAs agreed to, modified or acquired in business combinations on or after July 1, 2003, and concluded that all such PPAs contained a lease element requiring lease accounting. Accordingly, revenue related to the lease element of the PPA is presented as ‘‘lease portion of energy and capacity’’ revenue, with the remaining revenue related to the production and delivery of the energy being presented as ‘‘energy and capacity’’ revenue in the consolidated statements of operations. Future minimum lease revenues under PPAs which contain a lease element as of December 31, 2006 were as follows:


Year ending December 31:	(dollars in thousands)
2007		$	109,695
2008			112,268
2009			105,830
2010			103,518
2011			101,965
Thereafter			1,276,085
Total		$	1,809,361

141

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 14 — INCOME TAXES

Income from continuing operations before provision for income taxes, minority interest, and equity in income of investees consisted of:


	Year Ended December 31,
	2006			2005			2004
	(dollars in thousands)
U.S		$	14,306		$	702		$	8,436
Non-U.S. (foreign)			23,211			12,271			12,505
		$	37,517		$	12,973		$	20,941

The components of income tax expense are as follows:


	Year Ended December 31,
	2006				2005				2004
	(dollars in thousands)
Current:
Federal		$	—			$	—			$	—
Foreign			7,931				6,872				2,824
		$	7,931			$	6,872			$	2,824
Deferred:
Federal		$	157			$	577			$	2,772
State			304				132				86
Foreign			(1,989	)			(2,891	)			927
			(1,528	)			(2,182	)			3,785
		$	6,403			$	4,690			$	6,609

The significant components of the deferred income tax expense are as follows:


	Year Ended December 31,
	2006				2005				2004
	(dollars in thousands)
Deferred tax expense (exclusive of the effect of other components listed below)		$	8,272			$	10,089			$	6,433
Benefit of operating loss carryforwards — US			(4,341	)			(1,923	)			(3,575	)
Utilization of operating loss carryforwards — Israel			—				—				796
Change in valuation allowance			—				—				(796	)
Change in foreign income tax			(1,989	)			(2,891	)			927
Change in lease transaction			1,236				(7,457	)			—
Benefit of production tax credits			(4,706	)			—				—
		$	(1,528	)		$	(2,182	)		$	3,785

142

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The difference between the U.S. federal statutory tax rate and the Company’s effective rate are as follows:


	Year Ended December 31,
	2006			2005			2004
U.S. federal statutory tax rate		34.0	%		34.0	%		34.0	%
State income tax, net of federal benefit		0.8			0.7			0.3
Effect of foreign income tax, net		(7.0	)		(1.5	)		(2.4	)
Production tax credit		(12.5	)		—			—
Other, net		1.8			3.0			(0.3	)
Effective tax rate		17.1	%		36.2	%		31.6	%

The net deferred tax assets and liabilities consist of the following:


	December 31,
	2006				2005
	(dollars in thousands)
Deferred tax assets (liabilities):
Net foreign deferred taxes, primarily depreciation		$	(3,574	)		$	(5,563	)
Depreciation			(42,215	)			(33,840	)
Net operating loss carryforward — U.S.			17,184				12,843
Lease transaction			6,221				7,457
Investment tax credits			1,971				1,971
Production tax credits			4,706				—
Stock options amortization			239				—
Accrued liabilities and other			1,785				2,167
Total		$	(13,683	)		$	(14,965	)

Deferred taxes are included in the balance sheets as follows:


	December 31,
	2006				2005
	(dollars in thousands)
Among current assets		$	1,819			$	1,663
Among non-current assets			6,172				5,376
Among non-current liabilities			(21,674	)			(22,004	)
		$	(13,683	)		$	(14,965	)

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 asset at December 31, 2006 will be realized.

At December 31, 2006, the Company had U.S. federal NOL carryforwards of approximately $46.5 million and state NOL carryforwards of approximately $39.3 million, available to reduce future taxable income, which expire between 2021 and 2025 for federal NOLs and between 2014 and 2016 for state NOLs. The investment tax credits in the amount of $2.0 million at December 31, 2006 are available for a 20-year period and expire in 2022 and 2023. The production tax credits in the amount of $4.7 million at December 31, 2006 are available for a 20-year period and expire in 2025.

Through June 30, 2004, the Company had NOL carryforwards related to its Israeli operations of approximately $14.0 million available to reduce future taxable income, which could be carried over

143

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

indefinitely until utilized. However, despite the fact that the NOL carryforward period was indefinite, there is currently uncertainty as to the Israeli tax laws related to establishing limitations on the use of NOLs. In addition, there are uncertainties as to the ability to transfer those losses from the Parent. Due to these uncertainties, management reached the conclusion that it was not likely that such NOL carryforwards will be utilized. Subsequent to July 1, 2004, it was determined that the losses could not be transferred; therefore, the deferred tax assets in respect of the Parent’s NOL carryforwards and the valuation allowance relating to such deferred tax assets were removed.

The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $78.0 million at December 31, 2006. 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.

Tax benefits in the U.S.

The U.S. federal government encourages production of electricity from geothermal resources through certain tax subsidies. The Company is permitted to claim in its consolidated federal tax returns either an investment tax credit for approximately 10% of the cost of each new geothermal power plant or ‘‘production tax credits’’, which in 2006 were 1.9 cents per kWh and is adjusted annually for inflation, on the first ten years of electricity output, under the Energy Policy Act of 2005 that became law on August 8, 2005. (Production tax credits can only be claimed on new plants put into service between October 23, 2004 and December 31, 2008.) The Company, as the owner of any project that would be put in service during the period ending December 31, 2008, has to choose between the production tax credit and the investment tax credit.

Certain of the Company’s power purchase agreements that were in effect as of December 31, 2006 provide that all or a portion of the production tax credits are to be shared with the utility once they are monetized from the federal government. The Company has the ability to elect investment tax credits rather than production tax credits in its federal tax returns. Given the existing power purchase agreements, the Company would be economically compelled to elect investment tax credits for certain facilities thereby eliminating any amounts that would be due to the utilities under the production tax credit sharing arrangement. As such, the Company has not deferred revenue for such arrangements. The Company is in the process of negotiating the elimination of the production tax credit sharing provisions in exchange for a prospective reduction in the energy rate. Subsequent to December 31, 2006, the Company finalized one such amendment. Based upon negotiations to date and the expectations of the Company, the Company believes it is likely that the remaining power purchase agreements will be similarly modified. As a result, the Company has not anticipated the investment tax credits for purposes of its 2006 tax provision.

Income taxes related to foreign operations

The Philippines — From OLCL’s inception in 1996 to September 2003, OLCL, an 80% owned subsidiary (which was deconsolidated as of April 1, 2004) with operations in the Philippines, had an income tax holiday. Subsequent to September 2003, OLCL is subject to the Philippines regular corporate income tax rate of 32%.

Guatemala — The enacted tax rate is 31%. The Company was granted a benefit under a law which promotes development of renewable power sources. The law allows the Company to reduce the investment made in its geothermal project from income tax payable, which brings the effective tax rate to zero.

144

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Israel — The Company’s operations in Israel through OSL are taxed at the regular corporate tax rate of 36% in 2003, 35% in 2004, 34% in 2005, 31% in 2006, 29% in 2007, 27% in 2008, 26% in 2009 and 25% in 2010 and thereafter. OSL received from Israel’s Investment Center ‘‘Approved Enterprise’’ status under Israel’s Law for Encouragement of Capital Investments, 1959 (the ‘‘Investment Law’’), with respect to two of its investment programs. One such approval was received in 1996 and the other was received in May 2004. In respect of the approval from 1996, OSL has utilized all the tax benefits it was entitled to. Recently, due to a broad legislative amendment in the Investment Law, OSL replaced the certificate approval received in May 2004 from Israel’s Investment Center with a ruling from the Israeli Tax Authorities. The ruling was obtained in April 2006. By replacing the certificate of approval with a ruling, OSL maximized the tax benefits it is entitled to under the Investment Law. As an Approved Enterprise and according to the ruling, OSL was exempt from Israeli income taxes with respect to income derived from the approved investment for the years 2004 and 2005 and thereafter such income is subject to reduced Israeli income tax rates of 25% for an additional five years. These benefits are subject to certain conditions set forth in the ruling, including among other things, that all transactions between OSL and its affiliates are at arms length, and that the management and control of OSL will be from Israel during the whole period of the tax benefits. A change in control should be reported to the Israeli Tax Authorities in order to maintain the tax benefits. In addition, as an industrial company, OSL is entitled to accelerated depreciation on equipment used for its industrial activities.

Other significant foreign countries — The Company’s operations in Nicaragua and Kenya are taxed at the rates of 25% and 37.5%, respectively.

NOTE 15 — BUSINESS SEGMENTS

The Company has two reporting segments that are aggregated based on similar products, market and operating factors: electricity and products 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 pursuant to power purchase agreements. The products 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.

145

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summarized financial information concerning the Company’s reportable segments is shown in the following tables:


	Electricity			Products			Consolidated
	(dollars in thousands)
Year Ended December 31, 2006
Net revenues from external customers		$	195,483		$	73,454		$	268,937
Intersegment revenues			—			45,520			45,520
Depreciation and amortization expense			42,787			665			43,452
Operating income			50,314			11,614			61,928
Segment assets at year end*			1,104,326			55,776			1,160,102
Expenditures for long-lived assets			185,983			1,825			187,808
*Including unconsolidated investments			37,207			—			—
Year Ended December 31, 2005
Net revenues from external customers		$	177,369		$	60,623		$	237,992
Intersegment revenues			—			52,679			52,679
Depreciation and amortization expense			39,557			629			40,186
Operating income			56,831			7,078			63,909
Segment assets at year end*			864,968			49,512			914,480
Expenditures for long-lived assets			112,990			3,759			116,749
*Including unconsolidated investments			47,235			—			—
Year Ended December 31, 2004
Net revenues from external customers		$	158,831		$	60,399		$	219,230
Intersegment revenues			—			13,045			13,045
Depreciation and amortization expense			34,806			665			35,471
Operating income			55,895			6,549			62,444
Segment assets at year end*			812,816			37,272			850,088
Expenditures for long-lived assets			213,255			817			214,072
*Including unconsolidated investments			48,818			—			—

Reconciling information between reportable segments and the Company’s consolidated totals is shown in the following table:


	Year Ended December 31,
	2006				2005				2004
	(dollars in thousands)
Revenues:
Total segment revenues		$	268,937			$	237,992			$	219,230
Intersegment revenues			45,520				52,679				13,045
Elimination of intersegment revenues			(45,520	)			(52,679	)			(13,045	)
Total consolidated revenues		$	268,937			$	237,992			$	219,230
Operating income:
Operating income		$	61,928			$	63,909			$	62,444
Interest expense, net			(24,401	)			(51,009	)			(41,469	)
Non-operating income (expense) and other, net			(10	)			73				(34	)
Total consolidated income before income taxes, minority interest, and equity in income of investees		$	37,517			$	12,973			$	20,941

146

Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company sells electricity and products for power plants and others, mainly to the geographical areas according to location of the customers, as detailed below. The following tables present certain data by geographic area:


	Year Ended December 31,
	2006			2005			2004
	(dollars in thousands)
Revenues from external customers attributable to: ⁽¹⁾
North America		$	191,819		$	170,102		$	137,124
Pacific Rim			7,952			10,646			50,362
Latin America			23,353			13,741			13,548
Africa			10,636			10,553			10,142
Far East			6,174			1,127			4,569
Europe			29,003			31,823			3,485
Consolidated total		$	268,937		$	237,992		$	219,230


⁽¹⁾	Revenues as reported in the geographic area in which they originate.


	Year Ended December 31,
	2006			2005			2004
	(dollars in thousands)
Long-lived assets (primarily power plants and related
assets) located in:
North America		$	697,928		$	590,365		$	509,037
Latin America			105,332			38,682			26,938
Africa			49,570			51,311			53,423
Far East			—			—			571
Europe			6,220			5,060			1,837
Consolidated total		$	859,050		$	685,418		$	591,806

The following table presents revenues from major customers:


	Year Ended December 31,
	2006					2005					2004
	Revenues			%		Revenues			%		Revenues			%
	(dollars in thousands)					(dollars in thousands)					(dollars in thousands)
Revenues from major customers:
Customer A ⁽¹⁾		$	80,665		30		$	85,856		36		$	90,808		41
Customer B ⁽²⁾			—		—			5,281		2			31,058		14
Customer C ⁽¹⁾			34,320		13			33,583		14			28,298		13
Customer D ⁽¹⁾			40,517		15			36,207		15			15,470		7


⁽¹⁾	Revenues reported in Electricity Segment.


⁽²⁾	Revenues reported in Products Segment.

147

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 16 — TRANSACTIONS WITH RELATED ENTITIES

Transactions between the Company and the related entities during the years presented below and balances as of the dates presented below, other than those disclosed elsewhere in these financial statements, approximated:


	Year Ended December 31,
	2006			2005			2004
	(dollars in thousands)
Transactions
Revenues from an affiliate of the Parent		$	3,503		$	7,959		$	—
Property rental fee expense paid to Parent		$	628		$	627		$	627
Interest expense on note payable to Parent		$	8,367		$	10,635		$	9,723
Guarantee fees to Parent		$	29		$	204		$	548
Corporate financial, administrative and executive services provided to Parent		$	123		$	120		$	120
License fees to and services rendered by companies controlled by a shareholder of the Parent		$	122		$	162		$	—


	December 31,
	2006			2005
	(dollars in thousands)
Balances
Due from Orzunil		$	—		$	153
Due from subsidiary of Parent		$	120		$	167
Due from affiliate of Parent		$	566		$	—

The Company has an agreement with the Parent whereby, for a fee, the Parent maintains certain standby letters of credit on behalf of the Company. During the years ended December 31, 2006, 2005 and 2004, the fees under the agreement totaled approximately $29,000, $204,000 and $548,000, respectively.

The current liability due to (from) Parent at December 31, 2006 and 2005 of ($1,459.000) and $356,000, 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%, however not less than the change in the Israeli Consumer Price Index plus 4%, compounded quarterly, and is accrued and paid to the Parent annually.

Notes payable to Parent

In 2003, the Company entered into a loan agreement with the Parent, which was further amended on September 20, 2004 (‘‘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% during 2004 and 2003). The principal and interest on the Parent Loan Agreement are payable in varying amounts through the loan due date of June 2010. The outstanding balance of such loan at December 31, 2006 and 2005 was $89,488,000 (including current portion of $31,647,000) and $121,140,000 (including current portion of $31,647,000), respectively. As further discussed in Note 1, on June 29, 2004, $20.0 million outstanding under the Parent Loan Agreement was converted to 1,160,714 shares of $0.001 par value common stock of the Company.

148

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In 2003, the Company entered into a NIS 240.0 million non-interest bearing note agreement with the Parent. Principal is payable upon demand at any time after November 30, 2007, but no later than December 30, 2009. The loan is subordinated to all other liabilities of the Company. In accordance with the terms of such note, the Company will not be required to repay any amount in excess of $50,665,000 (using the exchange rate existing on the date of such note). As of December 31, 2006 and 2005, the ceiling of $50,665,000 is effective. Since the note is payable upon demand at any time after November 2007 it is presented in the balance sheet as of December 31, 2006 in current liabilities.

Future minimum payments under the notes payable to Parent (excluding the non-interest bearing note) as of December 31, 2006 are as follows:


Year ending December 31:	(dollars in thousands)
2007		$	31,647
2008			31,641
2009			16,600
2010			9,600
		$	89,488

Reimbursement agreement

On July 15, 2004, the Company entered into a reimbursement agreement with its Parent pursuant to which the Company agreed to reimburse its Parent for: (i) any draws made on any standby letter of credits issued by the Parent for the benefit of the Company; and (ii) any payments made under any guarantee provided by the Parent for the benefit of the Company. Interest on any amounts owing pursuant to the reimbursement agreement is payable at a rate per annum equal to the Parent’s average effective cost of funds plus 0.3% in U.S. dollars (see Note 16).

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 17 — EMPLOYEE BENEFIT PLAN

401(k) Plan

On July 1, 2002 the Company established a 401(k) Plan (the ‘‘Plan’’) for the benefit of its U.S. employees. Employees of the Company and its U.S. subsidiaries who have completed one year of service or who had one year of service upon establishment of the Plan are eligible to participate in the Plan. Contributions are made by employees through pretax deductions up to 60% of their annual salary. Contributions made by the Company are matched up to a maximum of 2% of the employee’s annual salary. The Company’s contributions to the Plan were $249,000, $228,000 and $185,000 for the years ended December 31, 2006, 2005 and 2004, respectively.

Severance plan

The Company, through OSL, 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

149

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 calculation of the benefit obligation. The liabilities for these plans are accounted for under the guidance of EITF Issue No. 88-1, Determination of Vested Benefit Obligation for a Defined Benefit Pension Plan , using what is commonly referred to as the ‘‘shut down’’ method, where a company records the undiscounted obligation as if it were payable at each balance sheet date. Such liabilities have been presented on the balance sheet as ‘‘Liabilities for severance pay’’. The Company has an obligation to partially fund the liabilities through regular deposits in pension funds and severance pay funds. The amounts funded amounted to $12,534,000 and $10,567,000 at December 31, 2006 and 2005, respectively, of which $10,981,000 and $9,201,000 respectively, were restricted, and have been presented on the balance sheet 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, 2006, 2005 and 2004 were $2,454,000, $771,000 and $537,000, respectively, which includes income (loss) amounting to $1,095,000, $(302,000) and $(122,000), respectively, generated from the regular deposits and amounts accrued in severance funds.

The Company expects the severance pay contributions in 2007 to be approximately $1.2 million.

The Company expects to pay the following future benefits to its employees upon their reaching normal retirement age:


Year ending December 31:	(dollars in thousands)
2007		$	794
2008			624
2009			702
2010			42
2011			668
2012-2016			4,296
		$	7,126

NOTE 18 — 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. Royalties’ expense under the geothermal resource agreements were $7,567,000, $6,910,000 and $4,716,000 for the years ended December 31, 2006, 2005 and 2004, respectively.

Letters of credit

In the ordinary course of business with customers, vendors, and lenders, the Company is contingently liable for performance under letters of credit totaling $17.4 million and $25.4 million at

150

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2006 and 2005, respectively (out of these amounts, letters of credit totaling $0 and $5.1 million, respectively, have been obtained by the Parent on behalf of the Company). 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.

LOC Agreement

A subsidiary of the Company has a letter of credit and loan agreement (‘‘LOC Agreement’’) with Hudson United Bank (‘‘HUB’’) pursuant to which HUB agreed to issue one or more letters of credit for an aggregate amount of up to $15.0 million. The LOC Agreement terminates on June 30, 2007, but is automatically extended for successive one-year periods unless notice is provided by either the Company or HUB to the contrary. In the event that HUB is required to pay on a letter of credit drawn by the beneficiary thereof, such letter of credit converts into a loan, bearing interest at 3-month LIBOR plus 4.0%, to be repaid in equal installments at the end of each of the next four quarters. There are various restrictive covenants in the LOC Agreement, which include maintaining certain levels of tangible net worth, leverage ratio, and minimum coverage ratio. Management believes that at December 31, 2006, the Company was in compliance with the covenants under the LOC Agreement. As of December 31, 2006 and 2005, no letters of credit were outstanding under the LOC Agreement.

Credit Agreement

On February 15, 2006, a subsidiary of the Company entered into a $25.0 million credit agreement (‘‘Credit Agreement’’) with Union Bank of California (‘‘UBOC’’). Under the Credit Agreement, the Company can request extensions of credit in the form of loans and/or the issuance of one or more letters of credit. UBOC 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, 2006, the Company was in compliance with the covenants under the Credit Agreement. As of December 31, 2006, three letters of credit with an aggregated stated amount of $21.9 million were issued and outstanding under the Credit Agreement.

Restrictive covenants

The Company entered into certain agreements with Israeli Banks under which the Company and its Israeli subsidiary, Ormat Systems Ltd., have agreed to certain negative covenants, including, but not limited to, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over the Company’s assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of the Company’s assets. In some cases, the Company and Ormat Systems Ltd. have agreed to maintain certain financial ratios such as a debt service coverage ratio and a debt to equity ratio. The Company does not expect that these covenants or ratios, which apply to the Company on a consolidated basis, will materially limit its ability to execute its future business plans or operations. The failure to perform or observe any of the covenants set forth in such agreements, subject to various cure periods, would result in the occurrence of an event of default and would enable the lenders to accelerate all amounts due under each such agreement.

151

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Grants and royalties

The Company, through OSL, has historically, through December 31, 2003, requested and received grants for research and development from the Office of the Chief Scientist of the Israeli Government. OSL 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 such grants, and amounted to $0, $1,342,000 and $1,833,000 for the years ended December 31, 2006, 2005 and 2004, respectively. The Company is not liable for royalties if the Company does not sell the respective products. Such royalties are capped at the amount of the grants received plus interest at LIBOR. The cap at December 31, 2006 and 2005, amounted to $1,138,000 and $4,723,000, respectively, of which approximately $277,000 and $244,000 of the cap, respectively, increases based on the LIBOR rate, as defined.

In addition, OSL is obligated to pay royalties to an unaffiliated entity at 2% of its domestic sales up to a cumulative amount of $9.25 million, and royalties at a rate of 0.2% of revenues on the next $5.4 million related to a certain technology that is not currently being utilized. However, no royalties will be paid after 30 years have elapsed from the completion of the related project. OSL has not derived any revenues from this technology to date, nor have any royalties been paid to date.

Employment agreements

The Company has employment agreements with four of its senior executive officers, the terms of which expire at various times through June 2008. Such agreements provide for monthly or annual base salary amounts, as well as for bonus and other benefits. The aggregate commitment for future salaries at December 31, 2006, excluding bonuses and benefits, was approximately $0.8 million.

Three of such executives are also entitled to change in control payments, whereby, if within three years following the occurrence of a change in control, the Company terminates the employee or the employee terminates his or her employment for good reason, as defined, or if, within 180 days following a change in control, the employee terminates his or her employment, the Company is required to pay 24 months of such employee’s monthly base salary at the time of the change in control, plus unpaid and accrued base salary and bonuses. The aggregate of 24 months of these executive’s base salary, excluding bonuses and benefits, as of December 31, 2006 approximated $0.9 million.

Contingencies

Steamboat Geothermal LLC (‘‘SG’’), a wholly owned subsidiary, is a party to a litigation related to a dispute over amounts owed to the plaintiffs under certain operating agreements. On December 31, 2005 and January 9, 2006, SG entered into a sales, settlement and release agreement and an assignment agreement, respectively, with an assignee of 37% of one of the plaintiffs’ right to net operating revenues, whereby SG was assigned such 37% of the net operating revenues of Steamboat 1 in partial settlement of the dispute with such plaintiff. The case is scheduled for mediation on April 10-11, 2007. The Company believes that any outcome of the dispute with regard to the remaining claims will not have a material impact on the Company’s results of operations.

One of the Company’s U.S. Subsidiaries is a party to a third-party complaint originally filed on November 15, 2005 by Lacy M. Henry and Judy B. Henry (the ‘‘Henrys’’) in a bankruptcy proceeding in the United States Bankruptcy Court for the Eastern District of North Carolina. The Henrys are debtors in a Chapter 11 bankruptcy filed in the Bankruptcy Court. The Henrys were the sole shareholders of MPS Generation, Inc. (‘‘MPSG’’). The Company entered into a supply contract with MPSG dated as of December 29, 2003, under which the Company was retained as a subcontractor to produce four waste heat energy converters for a project for which MPSG had entered into a contract with Basin Electric Power Cooperative (‘‘Basin’’). Basin filed a lawsuit on February 24, 2005 against,

152

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

among others, MPSG and the Henrys in the United States District Court for the District of North Dakota, alleging various causes of action including breach of contract, actual and constructive fraud, and conversion, and demanding the piercing of MPSG’s corporate veil to establish the personal liability of the Henrys for MPSG’s debts. On September 15, 2005, Basin filed a complaint commencing the bankruptcy adversary proceeding, seeking a determination that the claims which Basin alleged against the Henrys in the North Dakota lawsuit were not dischargeable. On November 15, 2005, the Henrys answered Basin’s complaint in the bankruptcy proceeding and also filed a third-party complaint against the subsidiary, alleging that to the extent the Henrys are found personally liable to Basin for MPSG’s debts, the Henrys have claims against the subsidiary for breach of contract/breach of warranty, tortious interference with contract, unfair or deceptive trade practices and fraud. The Henrys alleged damages in excess of $100 million. On December 15, 2005, the subsidiary filed an answer denying the Henrys’ claims and asserting counterclaims against the Henrys. The subsidiary filed a motion to dismiss the Henrys’ claims on January 31, 2006. On March 21, 2006, Basin filed an Amended Complaint in the bankruptcy proceeding, consolidating the causes of action it brought in the North Dakota lawsuit. In their answer to Basin’s Amended Complaint, the Henrys raised the same third party claims against the subsidiary. On May 11, 2006, the Bankruptcy Court entered an order denying the subsidiary’s motion to dismiss the Henrys’ claims against it, but staying the Henrys’ litigation against the subsidiary pending the resolution of Basin’s alter ego claims against the Henrys. In its answer to Basin’s Amended Complaint, MPSG asserted third party claims against the subsidiary similar to those claims raised by the Henrys. A trial on all issues raised in the bankruptcy proceeding is scheduled to begin in September 2007 in the Bankruptcy Court. The Company believes that it has no liability to the Henrys or to MPSG and intends to defend vigorously against the Henrys’ and MPSG’s claims in the bankruptcy proceeding. Therefore, no provision is included in the financial statements in respect of the claim.

Certain of the Company’s projects are subject to contested Federal Energy Regulatory Commission (‘‘FERC’’) rulings whereby an adverse outcome could result in a refund of a portion of previous revenues and/or a reduction in future revenues from those projects. The outcome of this matter cannot be predicted at this time.

As to the dispute with SCE regarding the supply of electricity the GEM 2 and GEM 3 plants to the Ormesa project, see Note 13.

The Company is a defendant in various other legal and regulatory proceedings in the ordinary course of business. It is the opinion of the Company’s management that the expected outcome of these matters, individually or in the aggregate, will not have a material effect on the results of operations and financial condition of the Company.

153

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 19 — QUARTERLY FINANCIAL INFORMATION (UNAUDITED)


	Three Months Ended
	March 31, 2005				June 30, 2005				Sept. 30, 2005				Dec. 31, 2005				March 31, 2006				June 30, 2006				Sept. 30, 2006				Dec. 31, 2006
	(dollars in thousands, except per share amounts)
Revenues:
Electricity Segment		$	40,452			$	42,394			$	51,385			$	43,138			$	43,733			$	48,767			$	56,402			$	46,581
Products Segment			13,444				13,631				17,905				15,643				16,588				15,319				21,446				20,101
			53,896				56,025				69,290				58,781				60,321				64,086				77,848				66,682
Cost of revenues:
Electricity Segment			23,612				27,791				25,855				26,357				26,867				30,936				32,319				34,234
Products Segment			10,683				11,427				12,073				11,053				10,532				9,580				13,157				17,946
			34,295				39,218				37,928				37,410				37,399				40,516				45,476				52,180
Gross margin			19,601				16,807				31,362				21,371				22,922				23,570				32,372				14,502
Operating expenses (income):
Research and development expenses			380				714				777				1,165				773				890				826				494
Selling and marketing expenses			2,208				1,651				1,934				2,083				2,695				2,826				2,410				2,430
General and administrative expenses			3,627				2,975				3,388				4,330				4,684				4,404				4,270				4,736
Gain on sale of geothermal resource rights			—				—				—				—				—				—				—				—
Operating income			13,386				11,467				25,263				13,793				14,770				15,450				24,866				6,842
Other income (expense):
Interest income			810				1,075				1,370				1,053				1,115				2,347				1,443				1,655
Interest expense			(10,298	)			(9,502	)			(9,011	)			(26,506	)			(7,453	)			(7,741	)			(8,347	)			(7,420	)
Foreign currency translation and transaction gain (loss)			(83	)			39				(21	)			(374	)			(8	)			(69	)			(933	)			306
Other non-operating income			40				72				53				347				103				204				65				322
Income (loss) before income taxes, minority interest and equity in income of investees			3,855				3,151				17,654				(11,687	)			8,527				10,191				17,094				1,705
Income tax benefit (provision)			(1,480	)			(1,154	)			(6,977	)			4,921				(1,914	)			(2,156	)			(4,342	)			2,009
Minority interest in earnings of subsidiaries			—				—				—				—				—				(571	)			(242	)			—
Equity in income of investees			1,533				2,097				1,641				1,623				1,279				931				1,429				507
Net income (loss)		$	3,908			$	4,094			$	12,318			$	(5,143	)		$	7,892			$	8,395			$	13,939			$	4,221
Earnings (loss) per share — basic and diluted		$	0.12			$	0.13			$	0.39			$	(0.16	)		$	0.25			$	0.24			$	0.39			$	0.12
Weighted average number of shares — basic			31,563				31,563				31,563				31,563				31,563				35,105				35,588				36,056
Weighted average number of shares — diluted			31,572				31,579				31,579				31,579				31,697				35,254				35,609				36,175

Interest expense for the three months ended December 31, 2005 include a one-time charge of approximately $16.6 million as a result of the prepayment on December 8, 2005 of the Beal Bank loan (see Note 9), comprised of: (i) prepayment premium of $11.5 million associated with payment of the Beal Bank loan, (ii) write-off of certain deferred financing costs amounting to $4.2 million associated with the incurrence of the Beal Bank loan, and (iii) loss of $0.9 million associated with the interest rate caps transaction described below. The tax effect of such one time charge is $6.3 million, bringing the net effect of it to $10.3 million.

154

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 20 — SUBSEQUENT EVENTS

As described in Note 6, on January 19, 2007, the Company entered into an Amended and Restated Power Purchase Agreement and a Project Security Agreement, with KPLC, the Kenyan parastatal electricity transmission and distribution company, with respect to Phase II of Olkaria III project.

On February 27, 2007, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $2.7 million ($0.07 per share) to all holders of the Company’s issued and outstanding shares of common stock on March 21, 2007, payable on March 29, 2007.

On February 27, 2007, the Company granted to a non-employee director non-qualified stock options, under the 2004 Incentive Compensation Plan, to purchase 7,500 shares of common stock at an exercise price of $38.85, which represented the fair value of the Company’s common stock on such date. Such options will expire seven years from the date of grant and will vest on the first anniversary of the date of grant.

155

ORMAT LEYTE CO. LTD .
A Limited Partnership

Financial Statements
December 31, 2005
(With Comparative Unaudited Figures
for 2006 and 2004)
(In United States Dollars)

and

Report of Independent Registered Public Accounting Firm
December 31, 2005

156

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Ormat Leyte Co. Ltd.

We have audited the accompanying balance sheet of Ormat Leyte Co. Ltd. (a Philippine limited partnership) (the Partnership) as of December 31, 2005, and the related statements of income, changes in partners’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes 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. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Ormat Leyte Co. Ltd. as of December 31, 2005, and the results of its operations and its cash flows for the year ended December 31, 2005 in conformity with U.S. generally accepted accounting principles.

/s/ SyCip Gorres Velayo & Co.

A Member Practice of Ernst & Young Global

Makati City, Philippines
March 27, 2006

SGV & Co is a member practice of Ernst & Young Global

157

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)

BALANCE SHEET


	December 31
	2006			2005
	(Unaudited)
Assets
Current Assets
Cash (Note 4)		$	1,268,147		$	1,316,091
Restricted cash (Notes 4 and 7)			3,570,920			3,781,222
Accounts receivable — net of allowance for doubtful debts of $698,461 in 2006 and $645,047 in 2005			1,779,104			1,725,143
Prepaid expenses			183,692			154,950
Due from related parties (Note 8)			1,899			—
Deferred income tax assets — net (Note 13)			744,274			994,965
Total Current Assets			7,548,036			7,972,371
Property, Plant and Equipment — net (Notes 2, 6, 7 and 14)			4,239,415			9,937,548
Deferred Income Tax Assets (Note 13)			—			587,248
Other Non-current Assets — net (Note 5)			392,529			741,893
		$	12,179,980		$	19,239,060
Liabilities and Partners’ Equity
Current Liabilities
Accrued expenses (Note 12)		$	476,636		$	490,746
Income tax payable (Note 13)			495,044			512,393
Current portion of long-term loan payable (Notes 4, 6 and 7)			3,809,828			5,079,776
Total Current Liabilities			4,781,508			6,082,915
Long-term Loan Payable — net of current portion (Notes 4, 6 and 7)			—			3,809,828
Total Liabilities			4,781,508			9,892,743
Partners’ Equity
Limited Partners (Notes 7 and 9)
Investment			158,000			395,000
Accumulated net income			5,677,283			6,988,589
			5,835,283			7,383,589
General Partner (Notes 7 and 9)
Investment			42,000			105,000
Accumulated net income			1,509,153			1,857,728
			1,551,153			1,962,728
Other Comprehensive Income — net of tax (Notes 3 and 12)			12,036			—
Total Partners’ Equity			7,398,472			9,346,317
		$	12,179,980		$	19,239,060

See accompanying Notes to Financial Statements.

158

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)

STATEMENT OF INCOME


	Years Ended December 31
	2006				2005				2004
	(Unaudited)								(Unaudited)
Operating Revenue (Notes 2 and 14)		$	13,715,296			$	13,133,937			$	10,799,895
Costs and Expenses
Costs of power plants operations (includes cost of services rendered by related parties amounting to $219,000 in 2006, $207,273 in 2005 and $186,000 in 2004) (Notes 6, 8, 10 and 14)			6,937,736				6,887,775				7,361,469
General and administrative expenses (includes cost of services rendered by a related party amounting to $99,000 in 2006, $87,273 in 2005 and $78,000 in 2004) (Notes 8 and 11)			360,086				256,825				212,199
			7,297,822				7,144,600				7,573,668
Recovery From Insurance (Note 14)			—				977,841				821,892
Income From Operations			6,417,474				6,967,178				4,048,119
Other Income (Charges)
Interest expense and finance charges (Note 7)			(424,188	)			(752,969	)			(1,095,328	)
Amortization of capitalized credit exposure fees (Notes 5 and 7)			(459,532	)			(459,532	)			(459,532	)
Interest income (Note 4)			186,286				126,103				34,284
Foreign exchange gain (loss) — net			90,715				(24,677	)			(32,790	)
Gain from non-monetary exchange of fixed assets			13,590				—				—
			(593,129	)			(1,111,075	)			(1,553,366	)
Income Before Tax			5,824,345				5,856,103				2,494,753
Income Tax Expense (Note 13)
Current			2,117,817				2,132,474				1,149,495
Deferred			918,909				(1,547,781	)			(12,325	)
			3,036,726				584,693				1,137,170
Net Income		$	2,787,619			$	5,271,410			$	1,357,583
Allocation of Net Income
Limited Partners		$	2,202,219			$	4,164,414			$	1,072,490
General Partner			585,400				1,106,996				285,093
		$	2,787,619			$	5,271,410			$	1,357,583

See accompanying Notes to Financial Statements.

159

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY


	Years Ended December 31
	2006				2005				2004
	(Unaudited)								(Unaudited)
Limited Partners
Investment:
Balance at beginning of year		$	395,000			$	1,297,145			$	2,853,710
Return of equity (Note 9)			(237,000	)			(902,145	)			(1,556,565	)
Balance at end of year			158,000				395,000				1,297,145
Accumulated net income:
Balance at beginning of year			6,988,589				5,910,457				6,028,062
Net income for the year			2,202,219				4,164,414				1,072,490
Income distribution (Note 9)			(3,513,525	)			(3,086,282	)			(1,190,095	)
Balance at end of year			5,677,283				6,988,589				5,910,457
			5,835,283				7,383,589				7,207,602
General Partner
Investment:
Balance at beginning of year			105,000				344,809				758,580
Return of equity (Note 9)			(63,000	)			(239,809	)			(413,771	)
Balance at end of year			42,000				105,000				344,809
Accumulated net income:
Balance at beginning of year			1,857,728				1,571,136				1,602,398
Net income for the year			585,400				1,106,996				285,093
Income distribution (Note 9)			(933,975	)			(820,404	)			(316,355	)
Balance at end of year			1,509,153				1,857,728				1,571,136
			1,551,153				1,962,728				1,915,945
Other Comprehensive Income — Net of tax (Notes 3 and 12)			12,036				—				—
Total Partners’ Equity		$	7,398,472			$	9,346,317			$	9,123,547

See accompanying Notes to Financial Statements.

160

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)

STATEMENT OF CASH FLOWS


	Years Ended December 31
	2006				2005				2004
	(Unaudited)								(Unaudited)
Cash Flows From Operating Activities
Net income		$	2,787,619			$	5,271,410			$	1,357,583
Adjustments for:
Depreciation			5,734,837				5,725,805				5,738,408
Deferred income tax			918,909				(1,547,781	)			(12,325	)
Amortization of capitalized credit exposure fees			459,532				459,532				459,532
Unrealized foreign exchange loss (gain) — net			(90,008	)			7,516				(5,017	)
Write-off of uncollectible accounts receivable			36,918				—				—
Provision for separation benefits			23,264				30,050				30,050
Gain from non-monetary exchange of fixed assets			(13,590	)			—				—
Changes in operating assets and liabilities:
Decrease (increase) in:
Accounts receivable			(55,056	)			934,220				(24,658	)
Prepaid expenses			(28,742	)			(23,108	)			25,544
Due from related parties			(1,899	)			—				—
Input value-added tax			(110,168	)			(20,078	)			(16,279	)
Increase (decrease) in:
Accrued expenses			(38,216	)			34,697				68,269
Income tax payable			(39,521	)			(49,279	)			137,982
Net cash provided by operating activities			9,583,879				10,822,984				7,759,089
Cash Flows From Investing Activities
Decrease in restricted cash			210,302				199,977				224,651
Acquisitions of property, plant and equipment			(23,114	)			(9,615	)			(3,417	)
Net cash provided by investing activities			187,188				190,362				221,234
Cash Flows From Financing Activities
Repayments of loan			(5,079,776	)			(5,079,776	)			(5,079,776	)
Income distributed to partners			(4,447,500	)			(3,906,686	)			(1,506,450	)
Return of equity to partners			(300,000	)			(1,141,954	)			(1,970,336	)
Cash used in financing activities			(9,827,276	)			(10,128,416	)			(8,556,562	)
Effects of Exchange Rate Changes on Cash and Cash Equivalents			8,265				(8,232	)			1,213
Net Increase (Decrease) In Cash and Cash Equivalnets			(47,944	)			876,698				(575,026	)
Cash and Cash Equivalents at Beginning of Year			1,316,091				439,393				1,014,419
Cash and Cash Equivalents at End of Year		$	1,268,147			$	1,316,091			$	439,393
Supplemental Disclosures of Cash Flow Information
Cash paid during the year for:
Income taxes		$	2,157,338			$	2,215,778			$	1,066,687
Interest and financing charges			478,951				808,187				1,152,821

See accompanying Notes to Financial Statements.

161

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
______________________________________________________________________________
NOTES TO FINANCIAL STATEMENTS


1.	Company Information


	a.	Background

Ormat Leyte Co. Ltd. (OLCL), a Philippine limited partnership (the Partnership), was registered with the Philippine Securities and Exchange Commission (SEC) to engage in power production. It owns and operates geothermal electricity-generating facilities in Leyte Province, Philippines for the production and sale of electricity from geothermal resources.

The partners in this Partnership are:


	Type of Partner	Percentage of Ownership
Orleyte Company — Philippine Branch (OC)	General		21.00
OC	Limited		58.97
Itochu Corporation	Limited		10.00
Electric Power Development Co., Ltd.	Limited		10.00
Ormat Philippines, Inc. — Philippine Branch (OPI)	Limited		0.03

The net income of the Partnership is allocated to the partners based on each partner’s respective percentage of ownership.

OLCL is registered with the Philippine Board of Investments as an operator of power generating plants on a pioneer status under the Omnibus Investments Code of 1987 (otherwise known as Executive Order No. 226). As a registered enterprise, OLCL is entitled to certain tax and nontax incentives under the provisions of the Code subject to certain requirements under the terms of its registration. No incentive was availed by the Partnership in 2006, 2005 and 2004.


	b.	Principal Business Risks

The risks associated with the power plants include operating risks, dependence on one customer, Philippine National Oil Company-Energy Development Corporation (PNOC-EDC), environmental and political risks. Operating risks include breakdown of equipment or processes and performance of the power plants below expected levels of output or efficiency (see Note 14).

There is concentration in credit risk due to dependence on one customer. If the government were to purchase PNOC-EDC’s property, PNOC-EDC would remain obligated under the Build-Operate-and-Transfer (BOT) Agreement (see Note 2) to make firm payments to OLCL. Such purchase could result in PNOC-EDC being unable to fulfill its obligations under the BOT Agreement, which will have material adverse effect on OLCL’s ability to service its debt requirements. OLCL controls this risk by strict monitoring procedures and continuous discussions with PNOC-EDC on matters relating to the BOT Agreement. Accounts receivable from PNOC-EDC as of December 31, 2006 and 2005 amounted to $1.78 million and $1.73 million, respectively, net of allowance for probable losses of $0.70 million and $0.65 million, respectively.


2.	BOT Agreement

On February 15, 1996, OLCL entered into an Accession Undertaking in connection with the BOT Agreement between Ormat, Inc., an affiliate company, and PNOC-EDC, a wholly-owned subsidiary of Philippine National Oil Company, whereby Ormat, Inc. assigned to OLCL all its rights and benefits under the BOT Agreement. The undertaking provides that OLCL shall design, construct, own and operate four geothermal electricity-generating plants with a total contracted capacity of 50 megawatts (MW) through the utilization of the geothermal resources of the Leyte Geothermal Power Optimization Project Area (Project).

162

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
______________________________________________________________________________
NOTES TO FINANCIAL STATEMENTS

The BOT Agreement provides that OLCL shall own, operate and maintain the power plants for the purpose of converting the steam delivered by PNOC-EDC into electric energy required by the National Power Corporation (NPC) in accordance with the power purchase agreement between NPC and PNOC-EDC during the cooperation period. OLCL will bill PNOC-EDC for the delivery of electric power and energy the amount of Capacity Fee which is the sum of the Fixed Operating Cost Recovery (the peso portion is payable in Philippine peso and the United States (US) dollar portion is payable in US dollar), Service Fee for Return on Investment (stated in US dollar and payable either in US dollar or Philippine peso) and Capital Cost Recovery (stated and payable in US dollar); and Energy Fee computed based on an agreed formula (stated and payable in Philippine peso), until the termination of the BOT Agreement in September 2007. The day following the end of the cooperation period, title to the power plants shall be transferred to PNOC-EDC, provided that PNOC-EDC has made all payments required pursuant to the BOT Agreement.

There are four power plants in the Leyte facility namely: Mahanagdong A, Mahanagdong B, Tongonan and Malitbog. The power plants became operational on September 25, 1997, except for Malitbog which became operational on December 31, 1997. The total costs of the power plants amounted to $56.67 million.


3.	Summary of Significant Accounting Policies

Basis of Preparation

The financial statements include the financial position, results of operations and cash flows of OLCL and have been prepared in accordance with US generally accepted accounting principles.

Use of Estimates

The preparation of the financial statements in accordance with US generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the financial statements and the reported amount of revenue and expenses during the reporting period. Actual results could differ from such estimates.

Functional Currency


	The	functional currency of OLCL is US dollar.

In 2004 and prior years, OLCL’s books of accounts were maintained in Philippine peso (₱) and were remeasured into US dollars. The resulting translation gain or loss was credited or charged to current operations. The remeasurement method of ₱ balances to US dollar balances was as follows:


	a.	All monetary assets and liabilities denominated in ₱ were translated into US dollars using the balance sheet date exchange rate;


	b.	Non-monetary assets, such as prepaid expenses, property, plant and equipment, other non-current assets and partners’ equity — investment account carried at historical cost, were translated at historical exchange rates on transaction dates; the related expense accounts such as depreciation and amortization were also translated at historical rates; and


	c.	Other revenue, costs and expenses denominated in ₱ were translated at the average exchange rate for the month.

Since January 1, 2005, OLCL has maintained its books of accounts in US dollar, consistent with its functional currency.

163

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
______________________________________________________________________________
NOTES TO FINANCIAL STATEMENTS

Adoption of New Accounting Standard

Effective January 1, 2006, OLCL adopted Statement of Financial Accounting Standards (SFAS) No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans . SFAS No. 158 amends SFAS 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plan and for Termination Benefits and SFAS No. 132 (revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits . SFAS No. 158 improves financial reporting by requiring an employer to recognize the overfunded or under funded status of a defined benefit postretirement plan (other than a multi employer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity or changes in unrestricted net assets of a not-for-profit organization. This Statement also improves financial reporting by requiring an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. As allowed under the transition provision of SFAS No. 158, gains and losses, prior service costs or credits and transition assets or obligations that have not yet been included in separation benefits cost as of December 31, 2006 are recognized as components of the ending balance of ‘‘Other comprehensive income,’’ net of tax, shown in the 2006 statement of partners’ equity.

The adoption resulted in the recognition of $12,036 in ‘‘Other comprehensive income,’’ net of tax effect of $6,961, and a corresponding reduction in Accrued separation benefits of $18,997 as of December 31, 2006 (see Note 12).

Accounts Receivable

Accounts receivable are recognized and carried at original invoice amount less an allowance for any uncollectible amounts. An estimate for doubtful accounts is made when collection of the full amount is no longer probable.

Property, Plant and Equipment

Property, plant and equipment are carried at cost less accumulated depreciation and any impairment in value. The cost of power plants consists of expenditures incurred in connection with the design and construction of the power plants. Cost also includes capitalized interests on borrowed funds used to finance the construction of the power plants during the construction period.


	For	the years ended December 31, 2006, 2005 and 2004, there was no interest capitalized.

Depreciation of the power plants is computed on the straight-line method over a period of
10 years, which is the cooperation period stipulated in the BOT Agreement. Depreciation of the other property and equipment is computed on the straight-line method over the estimated useful lives of the assets as follows:


Transportation equipment			5 years
Furniture, fixtures and equipment			3 years

The cost of routine repairs and maintenance is charged to income as incurred; major enhancements and improvements are capitalized. When property and equipment are retired or otherwise disposed of, the cost and accumulated depreciation and impairment losses, if any, are removed from the accounts and any resulting gain or loss is credited or charged to current operations.

Impairment of Long-lived Assets

Long-lived assets are accounted for in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-lived Assets . OLCL periodically evaluates its long-lived assets for

164

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
______________________________________________________________________________
NOTES TO FINANCIAL STATEMENTS

events or changes in circumstances that might indicate that the carrying amount of the assets may not be recoverable. OLCL assesses the recoverability of the assets by determining whether the amortization of such long-lived assets over their estimated useful lives can be recovered through projected undiscounted future cash flows. The amount of impairment, if any, is measured based on the fair value of the assets. Based on OLCL’s review, as of December 31, 2006, 2005 and 2004, no impairment of assets has occurred.

Deferred Costs

Credit exposure fees paid in relation to the term loan, included under the Other non-current assets account in the balance sheets, are deferred and amortized over the term of the loan up to July 2007 using the effective interest rate method.

Cash and Cash Equivalents

OLCL considers all highly liquid investments with original maturity of three months or less at the time of purchase to be cash and cash equivalents.

Prepaid Input Value-Added Taxes

Prepaid input value-added taxes (VAT) represent VAT imposed on OLCL by its suppliers for the acquisition of goods and services required under Philippine tax laws and regulations.

The input VAT is recognized as an asset and will be claimed as tax credits/refunds. Input taxes are stated at their estimated net realizable values.

Revenue Recognition

Pursuant to Emerging Issues Task Force Issue No. 01-8, Determining Whether an Arrangement Contains a Lease , and Statement of Financial Accounting Standards (SFAS) 13, Accounting for Leases , the arrangements of the BOT Agreement should be accounted for as an operating lease. The BOT Agreement does not provide for any minimum payments.

Operating revenue consists of Capacity and Energy Fees for the energy and services supplied by OLCL to PNOC-EDC as provided for in the BOT Agreement and revenue is recognized to the extent that it is probable that the economic benefits associated with the transaction will flow to OLCL and the amount of revenue can be reliably measured. Capacity Fee is the sum of the Fixed Operating Cost Recovery, Service Fee for Return on Investment and Capital Cost Recovery (see Note 2). The Capacity Fee component in OLCL’s BOT Agreement with PNOC-EDC is recognized based on the generation of electricity using the agreed formula in the BOT Agreement which takes into account, among others, the nominated capacity, contracted capacity, outage hours and an agreed fixed rate per kilowatt hour. Energy Fee is recognized based on the actual delivery of electricity generated and made available to PNOC-EDC in excess of the agreed efficiency rate in converting the steam delivered by PNOC-EDC into electric energy.

Interest on cash and restricted cash is recognized as the interest accrues computed using the effective interest rate method.

Separation Benefits

OLCL accrues the cost of separation benefits that the employees are entitled to receive at the termination of the BOT Agreement computed using the projected unit credit method. These benefits are unfunded. Starting December 31, 2006, actuarial gains and losses are charged or credited to ‘‘Other comprehensive income’’ in the statements of partners’ equity. Previously, actuarial gains and losses are taken to income.

165

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
______________________________________________________________________________
NOTES TO FINANCIAL STATEMENTS

Borrowing Costs

Borrowing costs generally are expensed as incurred. Borrowing cost is capitalized if it is directly attributable to the acquisition, construction or production of a qualifying asset. Capitalization of borrowing costs commences when the activities to prepare the asset are in progress and expenditures and borrowing costs are being incurred. Borrowing costs are capitalized until the assets are ready for their intended use. If the resulting carrying amount of the asset exceeds its recoverable amount, an impairment loss is recorded. Borrowing costs eligible for capitalization are the interest costs recognized on borrowings and other obligations.

Income Taxes

OLCL accounts for corporate income taxes in accordance with SFAS No. 109, Accounting for Income Taxes , which requires an asset and liability approach in determining income tax liabilities. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to the temporary differences between the financial reporting bases of assets and liabilities and their related tax bases. Deferred income tax assets and liabilities are measured using the tax rate expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is provided when it is more likely than not that a portion or all of the deferred income tax assets will not be realized in the future.

Foreign Currency Transactions

Transactions in foreign currencies are initially recorded in US dollars based on the exchange rates prevailing at the transaction dates. Foreign currency-denominated monetary assets and liabilities are translated to US dollars at exchange rates prevailing at balance sheet dates. Exchange gains or losses arising from the translation or settlement of foreign currency denominated monetary assets and liabilities at exchange rates different from those at which the assets and liabilities are initially recorded, are credited or charged to current operations.

Impact of Recently Issued Accounting Standards

In June 2006, the FASB issued FASB Interpretations (FIN) No. 48, Accounting for Uncertainty in Income Taxes . This Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes . This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Interpretation is effective for the fiscal years beginning after December 15, 2006. OLCL is still in the process of evaluating the impact of adopting FIN No. 48 effective January 1, 2007.

In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, Fair Value Measurements , which provides guidance for using fair value to measure assets and liabilities. It also responds to investors’ request for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value and the effect of fair value measurements on earnings. It applies whenever other standards require (or permit) assets or liabilities to be measured at fair value. It does not expand the use of fair value in any new circumstances. This Statement shall be effective for financial statements issued for fiscal years beginning after November 15, 2007.


4.	Cash and Restricted Cash

Restricted cash totalling $3.57 million and $3.78 million as of December 31, 2006 and 2005, respectively, represents the cash reserves under the Credit Agreement which will be used to

166

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
______________________________________________________________________________
NOTES TO FINANCIAL STATEMENTS

secure the payment of loan amortizations maturing in the succeeding two quarters (see Note 7). The balance of restricted cash is subject to distribution approvals in accordance with the Credit Agreement.


5.	Other Non-current Assets


	2006			2005
	(Unaudited)
Deferred credit exposure fees — net (Note 7)		$	229,808		$	689,340
Input VAT — net			160,396			50,528
Rental deposit			2,325			2,025
		$	392,529		$	741,893


6.	Property, Plant and Equipment


	2006			2005
	(Unaudited)
Power plants (Note 2)		$	56,667,169		$	56,667,169
Transportation equipment			169,758			181,120
Furniture, fixtures and equipment			78,388			75,697
			56,915,315			56,923,986
Less accumulated depreciation			52,675,900			46,986,438
		$	4,239,415		$	9,937,548

The carrying amounts of the power plants as of December 31, 2006 and 2005 were $4.19 million and $9.90 million, respectively.

Total depreciation charged to operations amounted to $5.73 million both in 2006 and 2005 and $5.74 million in 2004.

Interest expense capitalized up to the completion of the power plants in 1997, net of accumulated depreciation of $1.73 million and $1.55 million, amounted to $0.15 million and $0.33 million as of December 31, 2006 and 2005, respectively.

All power plants are pledged to secure the payment of the long-term loan payable (see Note 7).


7.	Long-term Loan Payable

The outstanding long-term loan payable amounted to $3.81 million and $8.89 million as of December 31, 2006 and 2005, respectively. The $3.81 million loan outstanding as of
December 31, 2006 is due in July 2007.

In 1998, the loan payable pertained to the construction credit facility extended by a syndicate of lenders to partially finance the cost of construction of 50 MW power plants in Leyte, Philippines.

The Export-Import Bank of the United States (Eximbank) provided a guarantee and agreed to re-finance the loan (i.e., conversion of this construction loan into a term loan upon completion of the reliability tests on the power plants) made by the lenders under the Credit Agreement.

The construction loan was converted into a term loan with Eximbank on January 21, 1999. The loan’s principal balance is payable in 35 equal, successive quarterly installments of
$1.27 million starting February 1, 1999 plus interest at 6.54% a year. The principal balance is

167

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
______________________________________________________________________________
NOTES TO FINANCIAL STATEMENTS

exclusive of credit exposure fees amounting to $0.23 million and $0.69 million (net of accumulated amortization of $3.65 million and $3.19 million) as of December 31, 2006 and 2005, respectively. The unamortized balance of credit exposure fees is included under the Other non-current assets account in the balance sheets (see Note 5).

The loan is collateralized by a mortgage on OLCL’s power plants, assignment of revenues and pledge of partnership interests of OPI and OC in OLCL.

The loan agreement provides, among other terms and conditions, that, for as long as the loan remains outstanding, OLCL is subject to certain negative covenants requiring prior written bank approval for specified partnership acts which include, but are not limited to mortgage of properties; consolidation, merger and sale of assets; declaration or payment of partnership distributions, return of capital or redemption, retirement, purchase or acquisition of partnership interests; entering into lease-purchase and guarantee agreements; contracting indebtedness; forming or having any subsidiaries; granting of loans or advances; entering into any new management contracts; amendment of Articles of Partnership and other organization documents,
i.e., changing its fiscal year and materially changing the nature of its present business; and abandonment of the Project. In addition, the agreement provides that OLCL’s equity-debt ratio should not be less than 25:75 at any time.


8.	Related Party Transactions

Transactions with related parties are as follows:


	a.	Technical and managerial support services agreement with Ormat Systems Ltd. (OSL), an affiliated company, for one year starting October 1997, renewable yearly, if not terminated prior to renewal date, until 2007, for a monthly fee of $10,000, escalated using the indexes as defined in the agreement (see Note 10).


	b.	Operation, maintenance, general and administration support services agreement with Ormat, Inc. — Manila Branch (OMB), an affiliate company, for a monthly service fee of $16,500 in 2006, $14,545 in 2005 and $12,000 in 2004 with the same terms as the agreement with OI (see Notes 10 and 11).


	c.	Noninterest-bearing short-term advances by the following related companies for payment of OLCL’s expenses which remained outstanding as of December 31, 2006:


OMB	$	1,887
OC		12
	$	1,899

There were no outstanding amounts due to/from related parties as of December 31, 2005.

168

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
______________________________________________________________________________
NOTES TO FINANCIAL STATEMENTS


9.	Partners’ Equity


	a.	OLCL returned equity to partners distributed in proportion to their respective contribution as follows:


Date of Return of Equity	Amount (in Millions)			Date of Approval of Amended Articles of Partnership
2006
November 9		$	0.30	December 5, 2006
2005
May 16		$	0.85	June 16, 2005
August 8			0.29	June 16, 2005
			1.14
2004
May 11			1.97	May 21, 2004


	b.	OLCL distributed income to partners as follows:


Date of Income Distribution	Amount (in Millions)
2006
February 7		$	1.45
May 16			1.10
August 8			1.10
November 9			0.80
			4.45
2005
February 3			0.48
May 5			0.80
August 8			1.42
October 3			1.21
			3.91
2004
February 9			1.20
August 9			0.31
			1.51

169

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
______________________________________________________________________________
NOTES TO FINANCIAL STATEMENTS


10.	Costs of Power Plants Operations


	2006			2005			2004
	(Unaudited)						(Unaudited)
Depreciation (Note 6)		$	5,734,837		$	5,725,805		$	5,738,408
Insurance			348,220			292,792			328,666
Salaries and wages			264,561			222,162			219,421
Technical and managerial services (Note 8a)			120,000			120,000			120,000
Operations and maintenance services (Note 8b)			99,000			87,273			66,000
Supplies and utilities			95,873			150,627			161,029
Employee benefits (Note 12)			76,019			103,620			72,046
Repairs and maintenance (Note 14)			60,269			47,287			536,726
Outside services			56,067			57,616			42,734
Others			82,890			80,593			76,439
		$	6,937,736		$	6,887,775		$	7,361,469


11.	General and Administrative Expenses


	2006			2005			2004
	(Unaudited)						(Unaudited)
Professional fees		$	167,392		$	83,308		$	67,792
Administrative services (Note 8b)			99,000			87,273			78,000
Bad debts and losses			36,918			39,767			—
Others			56,776			46,477			66,407
		$	360,086		$	256,825		$	212,199


12.	Separation Benefits

OLCL has a separation benefits policy that entitles its employees to a separation pay upon the termination of the BOT Agreement, equivalent to one month of the employee’s basic salary for every year of service for employees or a minimum of one and one fourth (1-1/4) month’s salary for every year of service for certain qualified employees. The separation benefits are unfunded.

Following is the movement of OLCL’s separation benefits liabilities included under the Accrued expenses account in the balance sheets:


	2006				2005
	(Unaudited)
Balance at beginning of year		$	122,481			$	85,604
Separation benefits cost for the year			23,264				30,050
Unrecognized actuarial gain (Note 3)			(18,997	)			—
Foreign exchange loss (gain)			10,342				6,827
Balance at end of year		$	137,090			$	122,481

The unrecognized actuarial gain in 2006, net of tax effect, was credited to other comprehensive income (see Note 3).

170

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
______________________________________________________________________________
NOTES TO FINANCIAL STATEMENTS

The principal assumptions used in determining the separation benefits liabilities as follows:


	2006	2005	2004
	(Unaudited)		(Unaudited)
Discount rate	5.55%	9.04%		11.67	%
Annual salary increases	8.00%	7.00%-8.00%		5.00	%


13.	Income Taxes


	a.	Deferred income tax assets relate to the following:


	2006			2005
	(Unaudited)
Deferred income tax assets — current:
Unrealized foreign exchange loss on current portion of long-term loan		$	525,458		$	814,156
Allowance for doubtful debts			244,461			225,766
Unrealized foreign exchange losses on current monetary items			129,551			102,041
Accrued separation benefits and others			89,265			78,768
			988,735			1,220,731
Less valuation allowance			244,461			225,766
Net deferred income tax assets — current		$	744,274		$	994,965
Deferred income tax asset on unrealized foreign exchange loss on long-term loan		$	—		$	587,248


	b.	The provision for income tax — deferred consists of the following:


	2006			2005				2004
	(Unaudited)							(Unaudited)
Net changes in temporary differences		$	812,282		$	559,132			$	692,642
Unrealized foreign exchange loss (gain)			87,932			1,952				(51	)
Changes in valuation allowance			18,695			(2,108,865	)			(704,916	)
		$	918,909			($1,547,781	)			($12,325	)

In 2004, based on the then position of the tax authorities on the tax treatment of foreign exchange differentials by taxpayers adopting the use of functional currency other than the Philippine peso financial statements, it was considered unlikely that the related temporary difference would be deductible against future taxable income. Thus, a valuation allowance amounting to $1,369,898 was provided on the deferred income tax asset relating to unrealized foreign exchange loss on the long-term loan in 2004. However, in 2005, the tax authorities changed their earlier position which rendered the temporary difference to be deductible against future taxable profits. Consequently, the valuation allowance on the deferred income tax asset in 2004 was reversed in 2005.


	c.	The reconciliations of the income tax expense computed by applying the statutory income tax rates to the income before income tax and the income tax expense as shown in the statements of income is summarized as follows:

171

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
______________________________________________________________________________
NOTES TO FINANCIAL STATEMENTS


	2006				2005				2004
	(Unaudited)								(Unaudited)
Income tax at statutory income tax rates		$	2,038,521			$	1,903,233			$	798,321
Additions to (reductions in) income tax resulting from:
Effect of using the local currency for tax purposes			986,932				937,166				138,207
Changes in valuation allowance on deferred income tax assets			18,695				(2,108,865	)			(704,916	)
Nondeductible expenses and others			(7,422	)			11,967				4,992
Depreciation expense related to capitalized foreign exchange losses			—				—				900,566
Change in income tax rate			—				(158,808	)			—
Income tax expense		$	3,036,726			$	584,693			$	1,137,170

The statutory income tax rates stood at 32% during the period up to October 31, 2005 and was increased to 35% from November 1, 2005 (Note d). The statutory income tax rate was 32% in 2004.

Computation of income tax expense is based on the books of accounts expressed in Philippine peso in accordance with Philippine’ tax laws. Prior to January 1, 2005, the carrying value of OLCL’s power plants in its books expressed in Philippine peso included undepreciated capitalized unrealized foreign exchange losses; the related depreciation charged to income was not considered a deductible tax item and was added back to ‘‘income tax at statutory income tax rates’’ in the reconciliation of income tax expense. Starting on January 1, 2005, OLCL reversed in its books of accounts expressed in Philippine peso the balance of undepreciated capitalized unrealized foreign exchange losses.


	d.	On May 24, 2005, the new Expanded Value-Added Tax (E-VAT) law was signed as Republic Act No. 9337 or the E-VAT Act of 2005. The E-VAT law took effect on November 1, 2005 following the approval on October 19, 2005 of Revenue Regulations 16-2005 which provides for the implementation of the rules and regulations of the new E-VAT law. This provides for the change in corporate income tax rate from 32% to 35% for the next three years effective on November 1, 2005, and 30% starting January 1, 2009 and thereafter, among others. OCLC’s deferred income tax assets in 2005 were measured using tax rates expected to apply for the years when the deferred income tax assets are expected to be realized.

The E-VAT law also provides for the increase in the VAT rate from 10% to 12%, subject to certain conditions. The increase in VAT rate to 12% became effective on February 1, 2006.


14.	Insurance Recovery of the Tongonan and Malitbog Plants


	a.	On July 11, 2004, the main step-up transformer of the Tongonan topping plant sustained damage, putting this plant into outage condition. Upon the insurance company’s instruction, OLCL procured a temporary unit located in the Philippines and on September 19, 2004, the plant’s normal operation was restored.

OLCL filed with its insurer claim for material damage on the costs incurred related to the damaged transformer in excess of $50,000 and for business interruption cover in excess of
30 days. OLCL did not recognize a receivable from the insurer as of December 31, 2004 since the insurer did not confirm the claim as of that date.

On May 26, 2005, OLCL recovered its insurance claims and credited $850,000 to the Recovery from insurance account in the 2005 statement of income.

172

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
______________________________________________________________________________
NOTES TO FINANCIAL STATEMENTS


	b.	On August 19, 2004, the generator at the Malitbog plant tripped placing the plant under the outage condition beginning that date. On January 8, 2005, the plant’s normal operation resumed after the generator rotor was repaired.

OLCL filed for material damage claim on the cost of the generator repair in excess of $50,000 and for business interruption cover in excess of 30 days. OLCL recognized a receivable of $1,200,000 as of December 31, 2004 since the insurer confirmed the claim and made an interim payment in January 2005. In the 2004 statement of income, $821,892 was credited to the Recovery from insurance account for the reimbursement of loss of revenue and $378,108 was credited to Repairs and maintenance account under Costs of power plants operations for the reimbursements of repair costs.

On April 13, 2005, OLCL recovered from the insurer $1,327,841 of which $1,200,000 was applied against the receivable set up in 2004 and the excess amount of $127,841 was credited to the Recovery from insurance account in the 2005 statement of income.


15.	Fair Values of Financial Instruments

The following table sets forth the carrying values and estimated fair values of OLCL’s financial instruments recognized as of December 31, 2006 and 2005:


	2006								2005
	Carrying				Fair				Carrying				Fair
	Values				Values				Values				Values
	(In Thousands)								(In Thousands)
Cash		$	1,268			$	1,268			$	1,316			$	1,316
Restricted cash			3,571				3,571				3,781				3,781
Accounts receivable			1,779				1,779				1,725				1,725
Long-term debt			(3,809	)			(3,809	)			(8,890	)			(8,578	)

The carrying amount of cash and restricted cash approximates their fair values since these are available for working capital and debt service requirements. The carrying amount of accounts receivable subject to normal credit terms, approximates its fair value.

The fair value of long-term debt as of December 31, 2006 already approximates its carrying value since the loan is already currently payable. The fair value in 2005 was based on the net present value of expected cash flows discounted using current interest rates, ranging from 3.59% to 4.44%, from similar debt with the same maturity and credit risk profile.


16.	Other Matters


	a.	Electric Power Industry Reform Act

Philippine Republic Act No. 9136, the Electric Power Industry Reform Act of 2001 (EPIRA), and the covering Implementing Rules and Regulations (IRR) provide for significant changes in the power sector, which include among others:


	i.	The unbundling of the generation, transmission, distribution and supply, and other disposable assets of a company, including its contracts with independent power producers, and electricity rates;


	ii.	Creation of a Wholesale Electricity Spot Market; and


	iii.	Open and non-discriminatory access to transmission and distribution systems.

The law also requires public listing of not less than 15% of common shares of generation and distribution companies within five years from the effectivity of the EPIRA. It provides cross

173

ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
______________________________________________________________________________
NOTES TO FINANCIAL STATEMENTS

ownership restrictions between transmission and generation companies and between transmission and distribution companies, and a cap of 50% of its demand that a distribution utility is allowed to source from an associated company engaged in generation, except for contracts entered into prior to the effectivity of the EPIRA.

There are also certain sections of the EPIRA, specifically relating to generation companies, which provide for: (a) cap on the concentration of ownership to only 30% of the installed capacity of the grid and/or 25% of the national installed generating capacity; and (b) value-added tax zero-rating of sale of generated power (see Note 13).

Based on the assessment of OLCL, it has complied with the applicable provisions of the EPIRA and its IRR.


	b.	Clean Air Act

The Clean Air Act and the related IRR contain provisions that have an impact on the industry as a whole, and on OLCL in particular, that need to be complied with within 44 months from the effectivity date or by July 2004. Based on the initial assessment made on its power plants’ existing facilities, OLCL believes it complies with the provisions of the Clean Air Act and the related IRR.


	c.	Pending Real Property Tax Assessment

On November 25, 2005, OLCL received a formal assessment for real property tax from the municipality of Kananga, Leyte amounting to $233,548 for the period from January 1, 2001 to October 31, 2005. According to the BOT Agreement, PNOC-EDC shall be responsible for the real property tax. On January 24, 2006, OLCL filed an appeal on the real property tax assessment with the Local Board of Assessment Appeals of the Leyte Province.

174

Table of Contents


ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.


ITEM 9A.	DISCLOSURE CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls

In connection with the preparation of this Annual Report on Form 10-K, management carried out an evaluation under the supervision and with the participation of, the Chief Executive Officer and Chief Financial Officer, as of December 31, 2006 of the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934, as amended (the Exchange Act), is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure. Based upon, and as of the date of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2006 at the reasonable assurance level.

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 such term is defined under Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended.

Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s consolidated financial statements for external purposes in accordance with generally accepted accounting principles.

The 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 the preparation of the consolidated financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with appropriate 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 consolidated financial statements.

Management, under the supervision and participation of the Chief Executive Officer and Chief Financial Officer, conducted an assessment of the Company’s internal control over financial reporting as of December 31, 2006 using the criteria established in Internal Control & Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of the Company’s internal control over financial

175

Table of Contents

reporting and testing of the operational effectiveness of the Company’s internal control over financial reporting. Based on such assessment, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2006.

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is presented in this Annual Report.

Changes in Internal Control Over Financial Reporting

No changes in our internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, occurred during the period covered by this annual report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


ITEM 9B.	OTHER INFORMATION

None.

176

Table of Contents

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 2007 Proxy Statement.

Directors and Executive Officers Information

The following table sets forth the name, age and positions of our directors, executive officers and persons who are executive officers of certain of our subsidiaries who perform policy making functions for us:


Name	Age		Position
Lucien Bronicki		73	Chairman of the Board of Directors; Chief Technology Officer ⁽³⁾
Yehudit ‘‘Dita’’ Bronicki		65	Chief Executive Officer; President; Director ⁽²⁾
Yoram Bronicki		40	Chief Operating Officer — North America; Director ⁽¹⁾
Joseph Tenne		51	Chief Financial Officer*
Nadav Amir		56	Executive Vice President — Engineering*
Hezy Ram		57	Executive Vice President — Business Development, North America**
Zvi Reiss		56	Executive Vice President — Project Management*
Joseph Shiloah		61	Executive Vice President — Marketing and Sales, Rest of the World*
Aaron Choresh		61	Vice President — Operations Rest of the World and Product Support*
Zvi Krieger		51	Vice President — Geothermal Engineering*
Etty Rosner		51	Vice President — Contract Administrator; Corporate Secretary*
Connie Stechman		51	Vice President
Independent Directors:
Dan Falk		62	Independent Director ⁽³⁾
Jacob J. Worenklein		58	Independent Director ⁽²⁾
Roger W. Gale		60	Independent Director ⁽¹⁾
Robert F. Clarke		64	Independent Director ⁽²⁾


*	Performs the functions described in the table, but is employed by Ormat Systems.


**	Performs the functions described in the table, but is employed by Ormat Nevada.


⁽¹⁾	Denotes Class I Director — Term expiring at 2008 Annual Shareholders Meeting.


⁽²⁾	Denotes Class II Director — Term expiring at 2009 Annual Shareholders Meeting.


⁽³⁾	Denotes Class III Director — Term expiring at 2007 Annual Shareholders Meeting.

Lucien Bronicki. Lucien Bronicki is the Chairman of our Board of Directors, a position he has held since our inception in 1994, and has also been our Chief Technology Officer since July 1, 2004. Mr. Bronicki co-founded Ormat Turbines Ltd. in 1965 and is the Chairman of the Board of Directors of Ormat Industries Ltd., the publicly-traded successor to Ormat Turbines Ltd., and 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

177

Table of Contents

manufacturer of image processing systems, until the end of 2005, and was the Co-Chairman of Orbotech Ltd., a NASDAQ-listed manufacturer of equipment for inspecting and imaging circuit boards and display panels. Mr. Bronicki has worked in the power industry since 1958. He is a member of the Executive Council of the Weizmann Institute of Science and was the Chairman of the Israeli Committee of the World Energy Council. Yehudit Bronicki and Lucien Bronicki are married. Mr. Bronicki obtained a postgraduate degree in Nuclear Engineering from Conservatoire National des Arts et Metiers, a Master of Science in Physics from Universite de Paris and a Master of Science in Mechanical Engineering from Ecole Nationale Superieure d’Ingenieurs Arts et Metiers. In the year 2005, he received a Ph.D. Honoris Causa from the Ben-Gurion University, and in 2006 from the Weizmann Institute of Science.

Yehudit ‘‘Dita’’ Bronicki. Yehudit Bronicki has been our Chief Executive Officer since July 1, 2004, and is also a member of our Board of Directors and our President. Mrs. Bronicki has also been the President of Ormat Systems, one of our subsidiaries, since July 1, 2004. Mrs. Bronicki was also a co-founder of Ormat Turbines Ltd. and is a member of the Board of Directors and the General Manager (a CEO-equivalent position) of Ormat Industries Ltd., the publicly traded successor to Ormat Turbines Ltd., and various of its subsidiaries. From 1992 to June 2005, Mrs. Bronicki was a director of Bet Shemesh Engines, a manufacturer of jet engines. In addition, Mrs. Bronicki was a member of the Board of Directors of OPTI Canada Inc. until May 2005 and is 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. Mrs. Bronicki obtained a Bachelor of Arts in Social Sciences from Hebrew University in 1965.

Yoram Bronicki. has been a member of our Board of Directors since November 12, 2004, and has been our Chief Operating Officer, North America since July 1, 2004. Mr. Bronicki is also a member of the Board of Directors of Ormat Industries Ltd., a position he has held since 2001, and a member of the Board of Directors of OPTI Canada Inc. From 2001 to 2004, Mr. Bronicki was Vice President of OPTI Canada Inc.; from 1999 to 2001, he was Project Manager of Ormat Industries Ltd. and Ormat International; from 1996 to 1999, he was Project Manager of Ormat Industries Ltd.; and from 1995 to 1996, he was Project Engineer of Ormat Industries Ltd. Mr. Bronicki is the son of Lucien and Yehudit Bronicki. Mr. Bronicki obtained a Bachelor of Science in Mechanical Engineering from Tel Aviv University in 1989 and a Certificate from the Technion Institute of Management Senior Executives Program.

Joseph Tenne. Joseph Tenne has served as our Chief Financial Officer since March 9, 2005. From 2003 to 2004, Mr. Tenne was the Chief Financial Officer of Treofan Germany GmbH & Co. KG, a German company. From 1997 until 2003, Mr. Tenne was a partner in Kesselman & Kesselman, Certified Public Accountants in Israel (a member firm of PricewaterhouseCoopers International Limited). Since January 8, 2006, Mr. Tenne has also been the Chief Financial Officer of Ormat Industries Ltd. Mr. Tenne is a member of the board of directors of 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 Engineering, since July 1, 2004. From 2001 through June 30, 2004, Mr. Amir 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.

Yeheskel (Hezy) Ram. Hezy Ram has served as our Executive Vice President of Business Development, North America, since January 1, 2004. From 1999 through December 31, 2003, Mr. Ram was Vice President of Business Development of Ormat Industries Ltd. Mr. Ram obtained a

178

Table of Contents

Master of Business Administration from Hebrew University in 1978, a Master of Science in Mechanical Engineering from Ben Gurion University in 1977 and a Bachelor of Science in Mechanical Engineering from Ben Gurion University in 1975.

Zvi Reiss. Zvi Reiss has served as our Executive Vice President of Project Management since July 1, 2004. From 2001 through 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 Marketing and Sales, Rest of the World, since July 1, 2004. From 2001 through June 30, 2004, Mr. Shiloah was the Executive Vice President of Marketing and Sales at Ormat Industries Ltd.; from 1989 to 2000, he was Vice President of Marketing and Sales of Ormat Industries Ltd.; from 1983 to 1989, he was Vice President of Special Projects of Ormat Turbines Ltd.; from 1984 to 1989, he was Operating Manager of the Solar Pond project of Solmat Systems Ltd., a subsidiary of Ormat Turbines Ltd.; and from 1981 to 1983, he was Project Administrator of the Solar Pond power plant project of Ormat Turbines Ltd. and Solmat Systems Ltd. Mr. Shiloah obtained a Bachelor of Arts in Economics from Hebrew University in 1972.

Aaron Choresh. Aaron Choresh has served as our Vice President of Operations Rest of the World and Product Support, since July 1, 2004. From 1999 through June 30, 2004, Mr. Choresh was the Vice President of Operations and Product Support of Ormat Industries Ltd.; from 1993 to 1998, he was the Director of Operations and Product Support of Ormat Industries Ltd.; from 1991 to 1992, he was Manager of Project Engineering and Product Support; and from 1989 to 1990, he was Manager of Project Engineering of Ormat Industries Ltd.. Mr. Choresh obtained a Bachelor of Science in Electrical Engineering from Technion Haifa in 1982.

Zvi Krieger. Zvi Krieger has served as our Vice President of Geothermal Engineering, since July 1, 2004. From 2001 through June 30, 2004, Mr. Krieger 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.

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, and Vice President of Contract Management of Ormat Industries Ltd., a position she has held since 1999. From 1991 to 1999, Ms. Rosner was Contract Administrator Manager and Corporate Secretary and from 1981 to 1991, she was the Manager of the Export Department and Office Administrative Manager. Ms. Rosner obtained a Diploma in General Management from Tel Aviv University in 1990.

Connie Stechman. Connie Stechman has served as our Vice President since our inception in 1994. Prior to joining Ormat Technologies, Inc., Ms. Stechman worked for an international public accounting firm. Ms. Stechman is a Certified Public Accountant and obtained a Bachelor of Science in Business and Concentration Accounting from California State University, Sacramento, in 1977.

Dan Falk. Dan Falk has been a member of our Board of Directors since November 12, 2004. Mr. Falk is also a member of the Board of Directors of Orbotech Ltd., Nice Systems Ltd., Attunity Ltd., ClickSoftware Technologies Ltd., Jacada Ltd. and Nova Measuring Instruments Ltd., all NASDAQ publicly traded companies. In addition, Mr. Falk serves as a member of the Board of Directors of the following public non-US companies: Plostopil Ltd., Orad Hi-Tech Systems Ltd., Dmatek Ltd., Netafim Ltd. and Poalim Ventures I Ltd. From 2001 to 2004, Mr. Falk was a business consultant to several public and private companies. From 1999 to 2000, Mr. Falk was Chief Operating Officer and Chief Executive Officer of Sapiens International NV. From 1995 to 1999, Mr. Falk was an

179

Table of Contents

Executive Vice President of Orbotech Ltd. From 1985 to 1995, Mr. Falk was Vice President of Finance and Chief Financial Officer of Orbot Systems Ltd. and of Orbotech Ltd. Mr. Falk obtained a Master of Business Administration from Hebrew University in 1972 and a Bachelor of Arts in Economics and Political Science from Hebrew University in 1968. Mr. Falk is the Chair of our Audit Committee. Our Board of Directors has determined that Mr. Falk qualifies as an Audit Committee ‘‘financial 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 7(d)(3)(iv) of Regulation 14A under the Securities Exchange Act of 1934.

Jacob J. Worenklein. Jacob J. Worenklein has been a member of our Board of Directors since November 12, 2004, and has also served as President and Chief Executive Officer of US Power Generating Company from 2003 to the present. From 1998 to 2003, he was Managing Director and Global Head of Project and Sectorial Finance for Societe Generale and, from 1996 to 1998, he was Managing Director and Head of Project Finance, Export Finance and Commodities for the Americas, for Societe Generale. Prior to joining Societe Generale in 1996, Mr. Worenklein was Managing Director and Global Head of Project Finance at Lehman Brothers and prior thereto was a partner and member of the executive committee of the law firm of Milbank, Tweed, Hadley & McCloy LLP, where he founded and headed the firm’s power and project finance practice. Mr. Worenklein served as Adjunct Professor of Finance at New York University and is a trustee of the Committee for Economic Development and a member of the Council on Foreign Relations. He is a member of the Board of Directors and Audit Committee of CDC Globeleq, an affiliate of the UK’s Commonwealth Development Corporation. Mr. Worenklein obtained a Bachelor of Arts from Columbia College in 1970 and a Juris Doctor and Master of Business Administration from New York University in 1973.

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 served 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 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. 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.

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 Securities Exchange Act of 1934, 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), Jacob Worenklein and Roger W. Gale, who are also independent directors of our company, as defined in Section 303A.02 of the NYSE Listed Company Manual.

180

Table of Contents


ITEM 11.	EXECUTIVE COMPENSATION

The information required under this item is incorporated by reference herein from the Company’s definitive 2007 Proxy Statement.


ITEM 12.	SECURITY OWNERSHIP AND CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required under this item is incorporated by reference herein from the Company’s definitive 2007 Proxy Statement.


ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required under this item is incorporated by reference herein from the Company’s definitive 2007 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 2007 Proxy Statement.

PART IV


ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(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
	1	.1	Underwriting Agreement, dated April 4, 2006, by and among the Company, Lehman Brothers Inc., and Goldman, Sachs & Co., for themselves and as representatives of the several underwriters named therein, incorporated by reference to Exhibit 1.1 to Ormat Technologies, Inc.’s Current Report on Form 8-K to the Securities and Exchange Commission on April 4, 2006.
	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	Second Amended and Restated By-laws, incorporated by reference to Exhibit 3.2 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.
	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.

181

Table of Contents


Exhibit No.			Document
	4	.3	Form of Rights Agreement by and between Ormat Technologies, Inc. and American Stock Transfer & Trust Company, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.
	4	.4	Indenture for Senior Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.
	4	.5	Indenture for Subordinated Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.
	10	.1.1	Credit Facility Agreement, dated September 5, 2000, between Ormat Momotombo Power Company and Bank Hapoalim B.M., incorporated by reference to Exhibit 10.1.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.1.2	Credit Agreement, dated as of December 18, 2003, among OrCal Geothermal Inc. and Beal Bank, S.S.B. and the financial institutions party thereto from time to time, incorporated by reference to Exhibit 10.1.5 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.1.3	Credit Agreement, dated May 13, 1996, between Ormat-Leyte and Export-Import Bank of the United States, incorporated by reference to Exhibit 10.1.6 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	.1.4	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	.1.5	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	.1.6	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.

182

Table of Contents


Exhibit No.			Document
	10	.1.7	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	.1.8	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	.1.9	Capital Note, dated December 22, 2003, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.11 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	.1.10	Amendment to Capital Note, dated September 20, 2004, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.12 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	.1.11	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	.1.12	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	.1.13	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	.1.14	Letter of Credit and Loan Agreement, dated June 30, 2004, by and between Ormat Nevada, Inc., and Hudson United Bank, incorporated by reference to Exhibit 10.1.16 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	.1.15	First Amendment to Letter of Credit and Loan Agreement, dated June 30, 2004, by and between Ormat Nevada, Inc., and Hudson United Bank, incorporated by reference to Exhibit 10.1.17 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	.1.16	Subordination Agreement, dated June 30, 2004, by and between Ormat Technologies, Inc. and Hudson United Bank, incorporated by reference to Exhibit 10.1.16 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.

183

Table of Contents


Exhibit No.			Document
	10	.2.1	Purchase Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd., incorporated by reference to Exhibit 10.2.2 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	.3.1	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	.3.2	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	.3.3	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	.3.4	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	.3.5	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	.3.6	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	.3.7	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	.3.8	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	.3.9	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.

184

Table of Contents


Exhibit No.			Document
	10	.3.10	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	.3.11	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	.3.12	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	.3.13	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	.3.14	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	.3.15	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	.3.16	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	.3.17	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	.3.18	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	.3.19	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.

185

Table of Contents


Exhibit No.			Document
	10	.3.20	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	.3.21	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	.3.22	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	.3.23	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	.3.24	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	.3.25	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	.3.26	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	.3.27	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	.3.28	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.

186

Table of Contents


Exhibit No.			Document
	10	.3.29	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	.3.30	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	.3.31	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	.3.32	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	.3.33	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	.3.34	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	.3.35	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	.3.36	Leyte Optimization Project BOT Agreement, dated August 4, 1995, by and between PNOC-Energy Development Corporation and Ormat Inc. incorporated by reference to Exhibit 10.3.36 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	.3.37	First Amendment to Leyte Optimization Project BOT Agreement, dated February 29, 1996, by and between PNOC-Energy Development Corporation and Ormat Leyte Co. Ltd. incorporated by reference to Exhibit 10.3.37 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

187

Table of Contents


Exhibit No.			Document
	10	.3.38	Second Amendment to Leyte Optimization Project BOT Agreement, dated April 1, 1996, by and between PNOC-Energy Development Corporation and Ormat Leyte Co. Ltd. incorporated by reference to Exhibit 10.3.38 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	.3.39	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	.3.40	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	.3.41	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	.3.42	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	.3.43	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	.3.44	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	.3.45	Firm Capacity Amendment to Purchase Power Contract, dated July 28, 1989, by and between Hawaii Electric Light Company and Puna Geothermal Venture incorporated by reference to Exhibit 10.3.45 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.46	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.

188

Table of Contents


Exhibit No.			Document
	10	.3.47	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	.3.48	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	.3.49	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	.4.1	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	.4.2	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	.4.3	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	.4.4	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	.4.5	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	.4.6	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.

189

Table of Contents


Exhibit No.			Document
	10	.4.7	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	.4.8	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	.4.9	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	.4.10	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	.4.11	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	.4.12	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	.4.13	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	.4.14	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	.4.15	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.

190

Table of Contents


Exhibit No.			Document
	10	.4.16	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	.4.17	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	.4.18	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	.4.19	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	.4.20	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	.4.21	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	.4.22	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	.4.23	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.

191

Table of Contents


Exhibit No.			Document
	10	.4.24	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	.4.25	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	.4.26	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	.4.27	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	.4.28	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	.4.29	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	.4.30	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	.4.31	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.

192

Table of Contents


Exhibit No.			Document
	10	.4.32	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	.4.33	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	.4.34	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	.5.1	Engineering, Procurement and Construction Contract, dated 2003, by and between Contact Energy Limited and Ormat Pacific Inc. incorporated by reference to Exhibit 10.5.3 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	.5.2	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	.5.3	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	.6.1	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	.6.2	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	.6.3	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	.7	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.

193

Table of Contents


Exhibit No.			Document
	10	.8	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	.9	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	.10.1	Form of Executive Employment Agreement of Hezy Ram incorporated by reference to Exhibit 10.10.1 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.
	10	.10.2	Amendment No. 1 to Form of Executive Employment Agreement of Hezy Ram incorporated by reference to Exhibit 10.10.2 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 20, 2004.
	10	.10.3	Amendment No. 2 to Form of Executive Employment Agreement of Hezy Ram, incorporated by reference to Exhibit 10.10.3 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	.11	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	.12	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	.13.1	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	.13.2	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	.14	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.

194

Table of Contents


Exhibit No.			Document
	10	.15	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	.16	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	.17	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	.18	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	.19	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	.20.1	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, filed herewith.
	10	.20.2	Olkaria III Project Security Agreement, dated January 19, 2007, between OrPower 4 Inc. and The Kenya Power and Lighting Company Limited, filed herewith.
	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.
	23	.2	Consent of SyCip Gorres Velayo & Co., 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.

195

Table of Contents


Exhibit No.			Document
	99	.1	Material terms with respect to BLM geothermal resources leases incorporated by reference to Exhibit 99.1 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 20, 2004.
	99	.2	Material terms with respect to BLM site leases incorporated by reference to Exhibit 99.2 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
	99	.3	Material terms with respect to agreements addressing renewable energy pricing and payment issues incorporated by reference to Exhibit 99.3 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

196

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized.


		ORMAT TECHNOLOGIES, INC.
Date: March 9, 2007	By:	/s/ YEHUDIT BRONICKI
		Name: Yehudit Bronicki Title: Chief Executive Officer, President and Director

Pursuant to the requirement of the Securities Act of 1934, this annual report has been signed below by the following persons on behalf of the Registrant in the capacities indicated, on March 9, 2007.


Signature		Capacity

/s/ YEHUDIT BRONICKI		Chief Executive Officer, President and Director (Principal Executive Officer)

Yehudit Bronicki

/s/ JOSEPH TENNE		Chief Financial Officer (Principal Financial and Accounting Officer)

Joseph Tenne

/s/ LUCIEN Y. BRONICKI		Chairman of the Board of Directors and Chief Technology Officer

Lucien Y. Bronicki

/s/ YORAM BRONICKI		Chief Operating Officer — North America and Director

Yoram Bronicki

/s/ DAN FALK		Director

Dan Falk

197


Exhibit No.			Document
	1	.1	Underwriting Agreement, dated April 4, 2006, by and among the Company, Lehman Brothers Inc., and Goldman, Sachs & Co., for themselves and as representatives of the several underwriters named therein, incorporated by reference to Exhibit 1.1 to Ormat Technologies, Inc.’s Current Report on Form 8-K to the Securities and Exchange Commission on April 4, 2006.
	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	Second Amended and Restated By-laws, incorporated by reference to Exhibit 3.2 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.
	4	.1	Form of Common Share Stock Certificate, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
	4	.2	Form of Preferred Share Stock Certificate, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
	4	.3	Form of Rights Agreement by and between Ormat Technologies, Inc. and American Stock Transfer & Trust Company, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.
	4	.4	Indenture for Senior Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.
	4	.5	Indenture for Subordinated Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.
	10	.1.1	Credit Facility Agreement, dated September 5, 2000, between Ormat Momotombo Power Company and Bank Hapoalim B.M., incorporated by reference to Exhibit 10.1.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.1.2	Credit Agreement, dated as of December 18, 2003, among OrCal Geothermal Inc. and Beal Bank, S.S.B. and the financial institutions party thereto from time to time, incorporated by reference to Exhibit 10.1.5 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.1.3	Credit Agreement, dated May 13, 1996, between Ormat-Leyte and Export-Import Bank of the United States, incorporated by reference to Exhibit 10.1.6 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.

198


Exhibit No.			Document
	10	.1.4	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	.1.5	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	.1.6	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	.1.7	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	.1.8	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	.1.9	Capital Note, dated December 22, 2003, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.11 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	.1.10	Amendment to Capital Note, dated September 20, 2004, by and between Ormat Technologies, Inc. and Ormat Industries Ltd., incorporated by reference to Exhibit 10.1.12 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	.1.11	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	.1.12	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	.1.13	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.

199


Exhibit No.			Document
	10	.1.14	Letter of Credit and Loan Agreement, dated June 30, 2004, by and between Ormat Nevada, Inc., and Hudson United Bank, incorporated by reference to Exhibit 10.1.16 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	.1.15	First Amendment to Letter of Credit and Loan Agreement, dated June 30, 2004, by and between Ormat Nevada, Inc., and Hudson United Bank, incorporated by reference to Exhibit 10.1.17 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	.1.16	Subordination Agreement, dated June 30, 2004, by and between Ormat Technologies, Inc. and Hudson United Bank, incorporated by reference to Exhibit 10.1.16 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	.2.1	Purchase Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd., incorporated by reference to Exhibit 10.2.2 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	.3.1	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	.3.2	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	.3.3	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	.3.4	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	.3.5	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	.3.6	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.

200


Exhibit No.			Document
	10	.3.7	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	.3.8	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	.3.9	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	.3.10	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	.3.11	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	.3.12	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	.3.13	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	.3.14	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	.3.15	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	.3.16	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.

201


Exhibit No.			Document
	10	.3.17	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	.3.18	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	.3.19	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	.3.20	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	.3.21	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	.3.22	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	.3.23	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	.3.24	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	.3.25	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.

202


Exhibit No.			Document
	10	.3.26	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	.3.27	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	.3.28	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	.3.29	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	.3.30	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	.3.31	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	.3.32	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	.3.33	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	.3.34	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.

203


Exhibit No.			Document
	10	.3.35	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	.3.36	Leyte Optimization Project BOT Agreement, dated August 4, 1995, by and between PNOC-Energy Development Corporation and Ormat Inc. incorporated by reference to Exhibit 10.3.36 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	.3.37	First Amendment to Leyte Optimization Project BOT Agreement, dated February 29, 1996, by and between PNOC-Energy Development Corporation and Ormat Leyte Co. Ltd. incorporated by reference to Exhibit 10.3.37 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	.3.38	Second Amendment to Leyte Optimization Project BOT Agreement, dated April 1, 1996, by and between PNOC-Energy Development Corporation and Ormat Leyte Co. Ltd. incorporated by reference to Exhibit 10.3.38 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	.3.39	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	.3.40	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	.3.41	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	.3.42	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	.3.43	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.

204


Exhibit No.			Document
	10	.3.44	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	.3.45	Firm Capacity Amendment to Purchase Power Contract, dated July 28, 1989, by and between Hawaii Electric Light Company and Puna Geothermal Venture incorporated by reference to Exhibit 10.3.45 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
	10	.3.46	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	.3.47	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	.3.48	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	.3.49	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	.4.1	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	.4.2	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	.4.3	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.

205


Exhibit No.			Document
	10	.4.4	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	.4.5	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	.4.6	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	.4.7	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	.4.8	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	.4.9	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	.4.10	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	.4.11	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	.4.12	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.

206


Exhibit No.			Document
	10	.4.13	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	.4.14	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	.4.15	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	.4.16	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	.4.17	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	.4.18	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	.4.19	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	.4.20	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	.4.21	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.

207


Exhibit No.			Document
	10	.4.22	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	.4.23	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	.4.24	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	.4.25	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	.4.26	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	.4.27	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	.4.28	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	.4.29	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.

208


Exhibit No.			Document
	10	.4.30	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	.4.31	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	.4.32	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	.4.33	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	.4.34	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	.5.1	Engineering, Procurement and Construction Contract, dated 2003, by and between Contact Energy Limited and Ormat Pacific Inc. incorporated by reference to Exhibit 10.5.3 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	.5.2	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	.5.3	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	.6.1	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	.6.2	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.

209


Exhibit No.			Document
	10	.6.3	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	.7	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	.8	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	.9	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	.10.1	Form of Executive Employment Agreement of Hezy Ram incorporated by reference to Exhibit 10.10.1 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.
	10	.10.2	Amendment No. 1 to Form of Executive Employment Agreement of Hezy Ram incorporated by reference to Exhibit 10.10.2 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 20, 2004.
	10	.10.3	Amendment No. 2 to Form of Executive Employment Agreement of Hezy Ram, incorporated by reference to Exhibit 10.10.3 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	.11	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	.12	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	.13.1	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.

210


Exhibit No.			Document
	10	.13.2	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	.14	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	.15	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	.16	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	.17	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	.18	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	.19	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	.20.1	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, filed herewith.
	10	.20.2	Olkaria III Project Security Agreement, dated January 19, 2007, between OrPower 4 Inc. and The Kenya Power and Lighting Company Limited, filed herewith.
	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.
	23	.2	Consent of SyCip Gorres Velayo & Co., Independent Registered Public Accounting Firm, filed herewith.

211


Exhibit No.			Document
	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.

212



DATED JANUARY 19, 2007

(1)  ORPOWER 4 INC.

(2)  THE KENYA POWER AND LIGHTING COMPANY LIMITED

                                   ----------

                  AMENDED AND RESTATED POWER PURCHASE AGREEMENT
                                       FOR
                          OLKARIA III GEOTHERMAL PLANT

                                   ----------


                                       i



                                    CONTENTS

CLAUSE                                                                      PAGE
------                                                                      ----

Clause 1:  Amendment and Restatement, Definitions and Interpretation ....      2

Clause 2:  Scope and Duration ...........................................     13

Clause 3:  Conditions Precedent and Security ............................     14

Clause 4:  Site .........................................................     17

Clause 5:  Geothermal Reservoir Appraisal and Development ...............     18

Clause 6:  Construction .................................................     20

Clause 7:  Commissioning and Testing ....................................     23

Clause 8:  Operating and Despatch Procedures ............................     25

Clause 9:  Maintenance and Repair .......................................     27

Clause 10: Sale and Purchase of Electricity .............................     30

Clause 11: Invoicing and Payment ........................................     31

Clause 12: Metering .....................................................     32

Clause 13: Insurance ....................................................     34

Clause 14: Undertakings and Warranties of the Parties ...................     34

Clause 15: Force Majeure ................................................     36

Clause 16: Termination and Default ......................................     38

Clause 17: Indemnification and Liability ................................     40

Clause 18: Confidentiality ..............................................     40

Clause 19: Dispute Resolution ...........................................     41

Clause 20: Maintenance and Operating Records ............................     43

Clause 21: Miscellaneous Provisions .....................................     44

Clause 22: Governing Law ................................................     47


                                       ii





SCHEDULES

List of Abbreviations ...................................................     48

Schedule 1:  Appraisal Programme ........................................     51

Schedule 2:  Facilities to be installed by KPLC and the Seller ..........     52
                Part A: Functional Specification of the Plant ...........     52
                Part B: The Seller's Connection Facilities including the
                        Transmission Interconnector and KPLC's
                        Connection Facilities ...........................     66
                Part C: Design Criteria - Transmission Interconnector ...     67
                Part D: Metering Equipment ..............................     96
                Part E: Delivery Point ..................................     98
                Part F: Rated Capacity ..................................     99
                Figure 1 General Map of the Area ........................    100
                Figure 2 Map Showing the Licence Area ...................    101
                Figure 3 Diagram of Early Generation Facility ...........    102
                Figure 4 Diagram of Plant ...............................    103

Schedule 3:  Maintenance Allowances of the Early Generation Facility and
             the Plant ..................................................    104

Schedule 4:  Procedures .................................................    106
                Part A: Commissioning and Testing Procedures ............    106
                Part B: Meter Procedures ................................    111
                Part C: Operating and Despatch Procedures ...............    114
                Figure 5 Correction Curves ..............................    117

Schedule 5:  Payment ....................................................    118
                Part A: Early Generation Tariff .........................    118
                Part B: Plant Tariff ....................................    124
                Part C: Invoicing .......................................    132
                Part D: Consumer Prices Index ...........................    133

Schedule 6:  Conditions Precedent .......................................    134
                Part A: Preconditions of the Seller .....................    134
                Part B: Preconditions of KPLC ...........................    134

Schedule 7:  Construction Programme .....................................    135

Schedule 8:  Parties' Addresses and Notice Details ......................    136

Schedule 9:  Insurance ..................................................    137
                Part A: Construction Period .............................    137
                Part B: Operating Period ................................    140

Schedule 10: Site Agreement .............................................    142


Schedule 11: Electricity Regulatory Board Approvals


                                       iii



THIS AMENDED AND RESTATED POWER PURCHASE AGREEMENT is made on January 19, 2007

BETWEEN

(1)  OrPower 4 Inc. a company incorporated in the Grand Cayman Islands, British
     West Indies, with its registered office in Grand Cayman, British West
     Indies, with an office at 6225 Neil Road, Suite 300, Reno, Nevada, USA and
     which will act through its branch at Off Moi South Lake Road, Hellsgate
     National Park, P.O. Box 1566-20117, Naivasha, Kenya ("the Seller"); and

(2)  The Kenya Power and Lighting Company Limited a company incorporated in
     Kenya with its registered office at Stima Plaza, P.O. Box 30099-00100,
     Nairobi, Kenya ("KPLC").

WHEREAS

A.   KPLC is entitled to purchase electricity generating capacity and to
     transmit and distribute electricity in the Republic of Kenya;

B.   Pursuant to a Request for Proposals ("RFP") dated 5th July 1996 and issued
     by MOE, the Seller has submitted an offer which has been accepted following
     the due process of the RFP;

C.   Pursuant to the RFP the Seller as the successful bidder was required to and
     entered into a power purchase agreement with KPLC;

D.   KPLC and OrPower 4 entered into the original Power Purchase Agreement dated
     5 November 1998, and subsequently entered into the First Supplemental
     Agreement dated 21 July 2000 modifying the terms of the original Power
     Purchase Agreement, and the Second Supplemental Agreement dated 17 April
     2003 modifying the terms of the original Power Purchase Agreement and of
     the First Supplemental Agreement;

E.   The Parties wish to reinstate certain of the changes from the First
     Supplemental Agreement and the second Supplemental Agreement to the
     original Power Purchase Agreement and to amend such agreement further;

F.   This Agreement is the amended and restated power purchase agreement agreed
     between the Parties, and which supersedes the original Power Purchase
     Agreement dated 5 November 1998, the First Supplemental Agreement dated 21
     July 2000, and the Second Supplemental Agreement dated 17 April 2003.

IT IS HEREBY AGREED as follows:


                                       1



CLAUSE 1: AMENDMENT AND RESTATEMENT, DEFINITIONS AND INTERPRETATION

1.1    AMENDMENT AND RESTATEMENT

With effect from the Signature Date, the original Power Purchase Agreement dated
5 November 1998, the First Supplemental Agreement dated 21 July 2000, and the
Second Supplemental Agreement dated 17 April 2003 between the Parties, inclusive
of all schedules thereto, shall be amended and restated in their entirety by
this Amended and Restated Power Purchase Agreement Power Purchase Agreement.

DEFINED TERMS:

In this Agreement, including the recitals, unless the context otherwise
requires, the following words and expressions shall have the following meanings:

"AGREEMENT" OR "PPA": this Amended and Restated Power Purchase Agreement
together with all schedules hereto as the same may be supplemented or amended
from time to time;

"ANSI": American National Standards Institute;

"API": American Petroleum Institute;

"APPRAISAL PERIOD": the period specified in the Appraisal Programme for the
conduct of the Appraisal Works;

"APPRAISAL PROGRAMME": the programme for the drilling of wells and the conduct
of other works to appraise the reserves and productivity of the Reservoir set
out in Schedule 1, as from time to time adjusted by the Parties in accordance
with this Agreement;

"APPRAISAL WORKS": the drilling and other works specified in the Appraisal
Programme;

"ASHRAE": American Society of Heating, Refrigerating and Air-Conditioning
Engineers;

"ASME": American Society of Mechanical Engineers;

"AUTHORISATIONS": any approval, consent, licence, permit, authorisation or other
permission granted by a Governmental Authority;

"AVAILABILITY FAILURE": a failure of any Settlement Period to deliver
electricity in accordance with a valid Despatch Instruction which Despatch
Instruction does not exceed the Declared Capacity, other than as a result of an
event on KPLC's System which was not caused by the Seller or any event of Force
Majeure;

"AVAILABLE EARLY GENERATION CAPACITY": the capacity of the Early Generation
Facility assumed to be Available in any Settlement Period being the Declared
Capacity unless there has been an Availability Failure in that Settlement Period
in which event the Available Early Generation Capacity shall be the average
Early Generation Availability achieved in response to Despatch Instructions for
that Settlement Period;


                                       2



"AVAILABLE PLANT CAPACITY": the capacity of the Plant assumed to be Available in
any Settlement Period being the Declared Capacity unless there has been an
Availability Failure in that Settlement Period in which event the Available
Plant Capacity shall be the average Plant Availability achieved in response to
Despatch Instructions for that Settlement Period;

"BACK-UP METERING EQUIPMENT": prior to the Full Commercial Operation Date, back
up equipment for metering and monitoring the operation and output of the Early
Generation Facility as may be supplied by KPLC and installed by the Seller as
specified in Part D of Schedule 2 and from the Full Commercial Operation Date,
back up equipment for metering and monitoring the output of the Plant as
supplied by KPLC and installed by the Seller as specified in Part D of Schedule
2;

"BID SECURITY": an on-demand performance bond in the amount of two hundred and
fifty thousand United States Dollars (US$250,000) drawn on an internationally
recognised bank;

"CAPACITY PAYMENTS": the amounts payable by KPLC in respect of the Contracted
Early Generation Capacity or Contracted Plant Capacity (as the case may be) in
accordance with Parts A and B of Schedule 5;

"CHANGE IN LAW": shall mean the adoption, promulgation, or modification after
the Signature Date of any Legal Requirement or the imposition upon the Seller of
any material condition in connection with the issuance, renewal, extension,
replacement or modification of any Authorisation after the Signature Date that
in either case establishes requirements for the design, construction, operation
or maintenance of the Plant or of the Geothermal Reservoir Development that are
materially more restrictive than the most restrictive requirements in effect as
of the Signature Date;

"COMMISSIONING": taking all steps necessary to put the Early Generation
Facility, the Plant and the Transmission Interconnector, as appropriate, into
operation including carrying out tests prior to operation as specified in Part A
of Schedule 4;

"CONFIDENTIAL INFORMATION": has the meaning ascribed thereto in Clause 18.1;

"CONNECTION FACILITIES": the connection facilities to be installed by the Seller
and KPLC as specified in Part B of Schedule 2;

"CONSTRUCTION BOND": an on-demand construction bond in the amount of one million
United States Dollars (US$1,000,000) drawn on an internationally recognised
bank;

"CONSTRUCTION PROGRAMME": the programme for the design, procurement,
construction, installation and commissioning of the Early Generation Facility
and the Plant set out in Schedule 7 and commencing on the Effective Date, as
from time to time adjusted by agreement of the Parties;

"CONSUMER PRICES INDEX OR CPI": the index known as "The Consumer Prices Index
for All Urban Consumers (CPI-U) for the US City Average for All Items 1982-84 =
100" as published by the United States Department of Labor, Bureau of Labor
Statistics, or such other index as the Parties may agree pursuant to Part D of
Schedule 5 or such replacement index as may be determined by an Expert which
replacement index shall take effect from such date as the Expert shall
determine;


                                       3



"CONTRACTED EARLY GENERATION CAPACITY": the capacity of the Early Generation
Facility at the reference conditions specified in paragraph 1.2(b)(ii) of Part A
of Schedule 2 being at the Signature Date twelve (12) MW or such other amount as
may be determined from time to time pursuant to Clauses 9.8, 9.10 and 9.11;

"CONTRACTED EARLY GENERATION CAPACITY TEST": a test of the normal full-load
capacity of the Early Generation Facility carried out in accordance with the
requirements of paragraph 3(b)(ii) of Part A of Schedule 4;

"CONTRACTED PLANT CAPACITY": the capacity of the Plant at the reference
conditions specified in paragraph 1.2(b)(ii) of Part A of Schedule 2 being at
the Signature Dated forty-eight (48) MW or such other amount as may be agreed or
determined from time to time pursuant to Clauses 5.4, 9.8A, 9.10 and 9.11;

"CONTRACTED PLANT CAPACITY TEST": a test of the normal full load capacity of the
Plant carried out in accordance with the requirements of paragraph 3(b)(ii) of
Part A of Schedule 4;

"DAILY LIQUIDATED DAMAGES SUM": an amount of US$0.50 per kW of Contracted Early
generation Capacity or Contracted Plant Capacity as the case may be;

"DECLARED CAPACITY": in respect of a Settlement Period the Early Generation
Capacity or Plant Capacity (as the case may be) declared by the Seller to be
Available for that Settlement Period in accordance with the Operating and
Despatch Procedure;

"DEFAULT": any one or more of the events specified in Clauses 16.1 and 16.2;

"DEFAULT RATE": two (2) percentage points above LIBOR;

"DELIVERY POINT": the point of common coupling on KPLC's System at which the Net
Electrical Output from the Early Generation Facility or the Plant (as the case
may be) is delivered and shall be the point specified in Part E of Schedule 2;

"DESPATCH INSTRUCTION": prior to the Full Commercial Operation Date, an
instruction given by KPLC to the Seller in relation to the operation of the
Early Generation Facility in accordance with Clause 8.3 and from the Full
Commercial Operation Date, an instruction given by KPLC to the Seller in
relation to the operation of the Plant in accordance with Clause 8.3;

"DIN": Deutsches Institut fur Normung (German standards institute);

"EARLY GENERATION AVAILABILITY": the ability of the Early Generation Facility
over a period of time, to deliver electricity to KPLC's System at the Delivery
Point and the terms "Available" and "Unavailable" as used in the context of the
Early Generation Facility shall be construed accordingly;

"EARLY GENERATION CAPACITY": the capacity of the Early Generation Facility,
expressed in MW to generate and deliver electricity at the Delivery Point
assuming the continued connection and proper operation of KPLC's System;


                                       4



"EARLY GENERATION CESSATION DATE": has the meaning ascribed thereto in Clause
6.1A;

"EARLY GENERATION COMMERCIAL OPERATION DATE": the date specified as such by the
Seller in accordance with Clause 7.9;

"EARLY GENERATION COMMERCIAL OPERATION TESTS": the respective tests to be
carried out on the Early Generation Facility, as specified in paragraph 3 of
Part A of Schedule4;

"EARLY GENERATION COMMISSIONING DATE": the date specified in the Construction
Programme as the target date for the start of Commissioning of the Early
Generation Facility, or such earlier date as the Seller may specify by notice to
KPLC not less than thirty (30) days before such earlier date subject to KPLC's
agreement to such earlier date which agreement shall not be unreasonably
withheld;

"EARLY GENERATION FACILITY": the generating facility with the Contracted Early
Generation Capacity described in paragraph 4 of Part A of Schedule 2, including
the Seller's 33 kV interconnection to the Early Generation Interconnection Point
and all transformers and associated equipment, relay and switching equipment,
and protective devices (adjusted to the settings agreed between KPLC and the
Seller pursuant to paragraph 4 Part A of Schedule 4) and all safety equipment;

"EARLY GENERATION FACILITY TESTS": the Contracted Early Generation Capacity Test
and Reliability Run Test;

"EARLY GENERATION INTERCONNECTION POINT": the physical point where the Early
Generation Facility and KPLC's transmission Interconnector are connected as
specified in Part E of Schedule 2;

"EARLY GENERATION LONG STOP COMMERCIAL OPERATION DATE": the date twenty-one (21)
months after the Effective Date or such other date as may be determined pursuant
to the provisions of this Agreement;

"EARLY GENERATION SITE": the land on which the Early Generation Facility shall
be located prior to the Full Commercial Operation Date;

"EFFECTIVE DATE": has the meaning ascribed thereto in Clause 3.1;

"EMERGENCY": a condition or situation that, in the sole but reasonable opinion
of KPLC, does materially and adversely, or is likely to materially and adversely
(i) affect the ability of KPLC to maintain a safe, adequate and continuous
electrical service to its customers, having regard to the then current standard
of electrical service provided to its customers, or (ii) present a physical
threat to persons or property for the security, integrity or reliability of
KPLC's System;

"ENERGY CHARGES": the amounts payable by KPLC in respect of the Net Electrical
Output as specified in Parts A and B Schedule 5;

"ESTABLISHMENT DATE": the date by which the last of the following activities and
events have occurred (except, with respect to Subclauses (ii), (iii) and (iv),
to the extent waived by the benefiting Party):


                                       5



     (i)   the Amended and Restated Power Purchase Agreement and the Olkaria III
           Project Security Agreement have been duly executed and delivered by
           the Parties after receipt of all necessary approvals;

     (ii)  the initial Letter of Credit has been issued in its full amount in
           favour of and delivered to the Seller;

     (iii) the Construction Bond has been issued in its full amount in favour of
           and delivered to KPLC as described in Clause 3.6 hereto; and

     (iv)  the Electricity Regulatory Board will have approved KPLC's
           application for pass through of the component of the Capacity Charges
           provided under Parts A and B of Schedule 5, or as may be otherwise
           agreed by KPLC and approved by the Electricity Regulatory Board.

"EVENT": has the meaning ascribed thereto in Part D of Schedule 5;

"EVENT OF DEFAULT": a failure by KPLC or the Seller to remedy a Default in
accordance with Clause 16.4;

"EXPERT": a person appointed in accordance with the provisions of Clause 19.2;

"FINANCING AGREEMENTS": the agreements relating to the provision of finance for
the construction of the Plant to be entered into between the Seller and banks or
other financial institutions;

"FORCE MAJEURE": has the meaning ascribed thereto in Clause 15.1;

"FULL COMMERCIAL OPERATION DATE": the date specified as such by the Seller in
accordance with Clause 7.10;

"FUNCTIONAL SPECIFICATION": the respective functional specifications for the
Early Generation Facility and the Plant as set out in Part A of Schedule 2;

"GEOTHERMAL RESERVOIR DEVELOPMENT": the works and operations required to be
carried out pursuant to Clauses 5.10 and 5.10A;

"GOK": The Government of the Republic of Kenya;

"GOOD FAITH DISPUTE PROCEDURE": means the procedure for resolution of disputes
or differences described in Clause 19.1;

"GOVERNMENTAL AUTHORITY": GOK, GOK owned or controlled corporations or
governmental agency, division or department or other authority including
regional or local authorities of Kenya;

"GWH": gigawatt hour being one thousand (1000) MWh;

"IEC": International Electrotechnical Commission;


                                       6



"IEEE": Institute of Electrical and Electronic Engineers;

"ISO": International Organisation for Standardisation;

"INTERCONNECTION POINT": the point of interconnection between the Transmission
Interconnector and KPLC's Connection Facilities as specified in Part E of
Schedule 2;

"INTERNATIONALLY APPLICABLE ENGINEERING STANDARDS": the latest issue of relevant
internationally recognised European, North American, Japanese or New Zealand
codes, practices and standards and the World Bank Environmental Guidelines, all
as specified in Part A of Schedule 2;

"KENGEN": the Kenya Electricity Generating Company Limited;

"KPLC'S CONNECTION FACILITIES": the equipment and facilities relating to the 220
kV substation at Olkaria II specified in Part B of Schedule 2;

"KPLC'S SYSTEM": the high voltage transmission system operated by KPLC, and the
distribution system(s) and ancillary electrical plant and equipment connected to
such transmission system;

"KPLC'S TRANSMISSION INTERCONNECTOR": the 33 kV interconnector specified in Part
A of Schedule 2 connecting the Early Generation Interconnection Point to KPLC's
System;

"KV": kilovolt, one thousand (1000) Volts;

"KW": kilowatts, one thousand (1000) Watts;

"KWH": kilowatt hour, one thousand (1000) Watt hours;

"LEGAL REQUIREMENT": any statute, law, regulation or other legislation, or any
order or directive of any Governmental Authority having jurisdiction in respect
of this Agreement or either Party;

"LETTER OF CREDIT": has the meaning ascribed to it in the Olkaria III Project
Security Agreement;

"LIBOR": in respect of any day, the offered rate for Unites States Dollars
quoted by Barclays Bank plc London or such other bank as the Parties shall from
time to time agree, to prime banks in the London Interbank Market at 11:00 hours
(London time) for a deposit of a principal sum equivalent to the sum n question
for a period commencing on such day and ending seven (7) days later provided
that if the said rate is not quoted on any day the rate last quoted shall be
used;

"LICENCE AREA": that area marked on Figure 1 of Schedule 2 Part A for indicative
purposes only being that area of land in the Universal Transverse Mercator (UTM)
Grid Zone 37, located on Map Series Y731 (D.O.S 423) Sheets 133/3 and 133/4,
Sakutiek and Longonot, published by GOK in 1975, enclosed by straight lines
joining adjacent points having the following co-ordinates:


                                       7





                        East (metres)   North (metres)
                        -------------   --------------
                        192 000         9 901 100
                        192 000         9 903 100
                        196 400         9 903 100
                        196 400         9 900 000
                        193 900         9 900 000;

"LONG STOP APPRAISAL WORKS START DATE": the date three (3) months after the
Effective Date;


"LONG STOP CONSTRUCTION START DATE": the date twenty-seven (27) months after the
Effective Date or such other date as may be determined pursuant to the
provisions of this Agreement;

"LONG STOP DATE": any of the Early Generation Long Stop Commercial Operation
Date, the Long Stop Appraisal Works Start Date, the Long Stop Construction Start
Date, the Long Stop Effective Date and the Long Stop Full Commercial Operation
Date;

"LONG STOP EFFECTIVE DATE": the date eighteen (18) months after the Signature
Date;

"LONG STOP FULL COMMERCIAL OPERATION DATE": the date falling thirty-six (36)
months after the Establishment Date, subject to an extension, at the Seller's
option, on a day by day basis for each day of Force Majeure, and for each day to
the extent by which a failure by KPLC to perform any of its obligations under
the PPA delays the Seller from achieving Full Commercial Operation prior to such
date;

"MAIN METERING EQUIPMENT": prior to the Full Commercial Operation Date, the main
metering equipment for metering and monitoring the operation and output of the
Early Generation Facility as supplied and installed by the Seller as specified
in Part D of Schedule 2 and from the Full Commercial Operation Date, the main
metering equipment for metering the output of the Plant as supplied and
installed by the Seller as specified in Part D of Schedule 2;

"METERING PARTY": has the meaning ascribed thereto in Clause 12.1;

"METERING SYSTEM": prior to the Full Commercial Operation Date, equipment for
metering and monitoring the operation and output of the Early Generation
Facility and from the Full Commercial Operation Date, equipment for metering and
monitoring the operation and output of the Plant as specified in Part D of
Schedule 2 which in both cases shall consist of the Main Metering Equipment, the
Back-Up Metering Equipment and all associated equipment;

"MOE": the Ministry of Energy of the Republic of Kenya;

"MW": megawatt, one thousand (1000) kW;

"MWH": megawatt hour, one thousand (1000) kWh;


                                       8



"NET ELECTRICAL OUTPUT": prior to the Full Commercial Operation Date,
electricity generated by the Early Generation Facility and delivered to KPLC at
the Delivery Point, and from the Full commercial Operation Date, electricity
generated by the Plant and delivered to KPLC at the Delivery Point, in both
cases net of all consumption (including imports and the Seller's Steam Field
Facilities) and of losses before the Delivery Point, or (where the context so
requires) a quantity (in kWh) of electricity so delivered;

"NON-DEFAULT RATE": LIBOR;

"NON-METERING PARTY": has the meaning ascribed thereto in Clause 12.2;

"NOTICE OF LIMITED RESERVOIR CAPACITY": the notice that may be given by the
Seller to KPLC pursuant to Clause 5.7;

"OLKARIA I": the geothermal power station and site owned by KenGen and known as
'Olkaria I';

"OLKARIA II": the geothermal power station and site owned by KenGen and to be
known as 'Olkaria II';

"OLKARIA III PROJECT SECURITY AGREEMENT": the agreement entered into by the
Parties on the Signature Date providing security to the Seller in respect of
KPLC's payment obligations under Clause 11 of this Agreement, as the same may be
supplemented or amended from time to time;

"OPERATING CHARACTERISTICS": the respective performance and operating
characteristics of the Early Generation Facility or the Plant for which values
are specified in the Functional Specification;

"OPERATING AND DESPATCH PROCEDURES": the procedures set out in Part C of
Schedule 4 and such further procedures as shall apply pursuant to Clauses 8.4
and 8.5;

"OPERATING AND MAINTENANCE AGREEMENT": the agreement entered into by the Seller
for the operation and maintenance of the Early Generation Facility and the
Plant;

"OPERATING PERIOD": the period from the Full Commercial Operation Date until the
end of the Term;

"OPERATING YEAR": a period of one (1) year beginning on the Full Commercial
Operation Date or any anniversary thereof;

"PARTIES": KPLC and the Seller and "PARTY" means either of them;

"PLANNED MAINTENANCE": maintenance of the Early Generation Facility or the Plant
(as the case may be) which has been planned in accordance with Clause 9.3, or
where the context admits the period allowed or the dates planned for such
maintenance;

"PLANT": the plant (consisting after the Early Generation Cessation Date, of the
Early Generation Facility and other equipment) described in Part A of Schedule
2, and including, where appropriate, the Seller's Connection Facilities, and the
Metering System;


                                       9



"PLANT ANNUAL TARGET OUTPUT": has the meaning ascribed thereto in paragraph 7 of
Part B of Schedule 5;

"PLANT AVAILABILITY": the ability of the Plant over a particular period of time,
to deliver electricity to KPLC's System at the Delivery Point and the terms;

"AVAILABLE" and "UNAVAILABLE": as used in the context of the plant shall be
construed accordingly;

"PLANT CAPACITY": the capacity of the Plant, expressed in MW, to generate and
deliver electricity at the Delivery Point assuming the continued connection and
proper operation of KPLC's System;

"PLANT COMMERCIAL OPERATIONS TESTS": the respective tests to be carried out on
the Plant, as specified in paragraph 3 of Part A of Schedule 4;

"PLANT COMMISSIONING DATE": the date specified in the Construction Programme as
the target date for the start of Commissioning of the Plant, or such earlier
date as the Seller may specify by notice given to KPLC not less than thirty (30)
days before such earlier date subject to KPLC's agreement to such earlier date
which agreement shall not be unreasonably withheld;

"PROJECT AGREEMENTS": the Operating and Maintenance Agreement, the Site
Agreement, and the Turnkey Construction Agreement;

"PRUDENT OPERATING PRACTICE": in relation to either Party, standards of practice
obtained by exercising that degree of skill, diligence, prudence and foresight
which could reasonably be expected from a skilled and experienced operator
engaged in the same type of undertaking under the same or similar circumstances;

"RATED CAPACITY": the respective electrical output ratings of the Early
Generation Facility and the Plant as set forth in Part F of Schedule 2;

"RELIABILITY RUN TEST": has the meaning ascribed thereto in paragraph 3(b)(I)
and 3(b)(iii) Schedule 4;

"REMEDIAL PROGRAMME": has the meaning ascribed thereto in Clause 16.4(a)(ii);

"REQUIRED EARLY GENERATION COMMERCIAL OPERATION DATE": the date eighteen (18)
months after the Effective Date or such other date as may be determined in
accordance with this Agreement;

"REQUIRED FULL COMMERCIAL OPERATION DATE": the date twenty (20) months and two
(2) weeks after the Establishment Date, subject to extension, at the Seller's
option, on a day by day basis for each day of Force Majeure, and for each day by
the extent to which a failure by KPLC to perform any of its obligations under
the PPA delays the Seller from achieving Full Commercial Operation prior to such
date;

"RESERVOIR": the subsurface body of hot water and steam located under the
Licence Area;


                                       10



"SCADA": Supervisory Control and Data Acquisition;

"SELLER'S CONNECTION FACILITIES": the Connection Facilities to be installed by
the Seller in accordance with Parts B and C of Schedule 2;

"SELLER'S STEAM FIELD FACILITIES": the Steam Field Facilities to be installed by
the Seller pursuant to this Agreement;

"SETTLEMENT PERIOD": a period of thirty (30) minutes beginning on the hour or
the half-hour;

"SIGNATURE DATE": the date of this Agreement;

"SITE": the land on which the Plant shall be installed by the Full Commercial
Operation Date;

"SITE AGREEMENT": the agreement substantially in the form specified in Schedule
10 and in accordance with Clause 4 which is to be entered into between a
Governmental Authority and the Seller permitting the Seller to acquire such
rights in the Licence Area as shall enable the Seller to perform its obligations
under this Agreement;

"STEAM FIELD FACILITIES": equipment, plant and facilities above ground and
underground, including wells, used in connection with the exploration,
appraisal, development and operation of geothermal reservoirs for electricity
generation;

"SYSTEM CHARACTERISTICS": has the meaning ascribed thereto in paragraph 4.3(a)
of Part A of Schedule 2;

"TARGET EFFECTIVE DATE": the date three (3) months after the Signature Date or
such other date as the Parties may agree;

"TARGET ESTABLISHMENT DATE": 15th December 2006;

"TAXES AND DUTIES": all forms of taxation, impost, levy or duty (including
without limitation, value added tax) imposed pursuant to the laws of the
Republic of Kenya in respect of the sale of electricity or on the purchase,
import and use or consumption of any real property, services, plant, equipment
or materials used in connection therewith or in respect of the right or act of
making capacity available or producing, delivering or transmitting electricity
which result directly or indirectly in an increase or decrease in the
construction, financing, operation or maintenance costs of the Seller in
performing its obligations under this Agreement provided that for the avoidance
of doubt Taxes and Duties do not include any form of taxation, impost, levy or
duty imposed on the income of the Seller upon which income tax is chargeable
under section 3(2) of the Income Tax Act CAP 470 as the same may be modified,
amended or replaced from time to time;

"TEMA": Tubular Exchanger Manufacturers Association;

"TERM": the period from the Signature Date until expiry of this Agreement in
accordance with Clause 2.2 or earlier termination;

"TRANSMISSION INTERCONNECTOR": the high voltage interconnector specified in
Parts B and C of Schedule 2;


                                       11



"TURNKEY CONSTRUCTION AGREEMENTS": the agreements entered into by the Seller for
the construction of the Early Generation Facility and the Plant;

"UNIT": a binary energy converter, including associated equipment, as comprised
in the Plant or the Early Generation Facility as specified in Part A of Schedule
2;

"UNITED STATES DOLLARS" OR US$": the lawful currency of the United States of
America for the time being and from time to time;

"UNIT COMMERCIAL OPERATION TESTS": the tests to be carried out on each of the
Units as specified in paragraph 2 of Part A of Schedule 4;

"UNIT TESTS": the tests to be carried on each of the Units as specified in
paragraph 1 of Part A of Schedule 4 and the Unit Commercial Operation Tests;

"VOLT": the unit of electrical potential as defined in the International
Standards Organisation standard ISO 1000:1992 Specification for SI Units and
Recommendations for Use of Their Multiples and of Certain Other Units;

"WATTS": the unit of electrical power defined as one (1) joule per second as
defined in International Standards Organisation standard ISO 1000:1992
Specification for SI Units and Recommendations for Use of Their Multiples and of
Certain Other Units;

"WATT HOURS": three thousand six hundred (3600) joules as defined in
International Standards Organisation standard ISO 1000:1992 Specification for SI
Units and Recommendations for Use of Their Multiples and of Certain Other Units;

"WEEK": a period of seven (7) days beginning on a Monday;

1.2     INTERPRETATION: In this Agreement, unless the context otherwise
        requires:

        (a)  reference to a business day is a reference to any day which is not
             a Saturday, Sunday or recognised public holiday in Kenya;

        (b)  reference to a day or a month is a reference to a calendar day or
             calendar month;

        (c)  references to Clauses, Schedules, Paragraphs and Figures are
             references to clauses, schedules, paragraphs and figures of and to
             this Agreement;

        (d)  words in the singular shall be interpreted as referring to the
             plural and vice versa, and words denoting natural persons shall be
             interpreted as referring to corporations and any other legal
             entities and vice versa;

        (e)  a requirement that a payment to be made on a day which is not a
             business day shall be construed as a requirement that the payment
             be made on the next business day;


                                       12



        (f)  in the event of a conflict between the Clauses and the Schedules,
             the Clauses shall prevail save for Schedule 10 which Schedule shall
             prevail;

        (g)  the term "including" shall be construed without limitation;

        (h)  headings are for convenience only and shall not affect the
             construction of the Agreement;

CLAUSE 2: SCOPE AND DURATION

2.1     SCOPE: The Seller shall:

        (i)   perform its obligations contained in the Appraisal Programme;

        (ii)  conduct the Geothermal Reservoir Development;

        (iii) design, procure, construct, finance, test, and commission the
              Transmission Interconnector;

        (iv)  design, procure, construct, finance, test, commission, operate and
              maintain the Early Generation Facility and the Plant;

        (v)   seek to make available the Contracted Early Generation Capacity
              and the Contracted Plant Capacity in compliance with the Operating
              Characteristics;

        (vi)  sell the Net Electrical Output to KPLC in accordance with and
              subject to the terms and conditions of this Agreement.

        The Parties hereby acknowledge that, as of the date hereof, all of the
        obligations, requirements and arrangements under Sub clauses (i) and
        (ii) above have been satisfied in full.

        KPLC shall purchase and pay for Available Early Generation Capacity and
        Available Plant Capacity and Net Electrical Output, in accordance with
        and subject to the terms and conditions of this Agreement.

2.2     TERM OF AGREEMENT: This Agreement shall come into force on the Signature
        Date and shall continue in force until the expiry of a period of twenty
        (20) years unless earlier terminated in accordance with its terms
        provided that:

        2.2.1 the period of twenty (20) years shall commence on the Full
              Commercial Operation Date where the Seller constructs, in
              accordance with Clause 5, a Plant with a Contracted Plant Capacity
              greater than the Contracted Early Generation Capacity; or

        2.2.2 the period of twenty (20) years shall be deemed to have commenced
              at the Early Generation Commercial Operation Date where following
              the delivery of a Notice of Limited Reservoir Capacity the Parties
              agree or an Expert determines that the Reservoir cannot support a
              Contracted Plant Capacity greater than the Contracted Early
              Generation Capacity save that if KPLC is


                                       13



              required by the Seller to pay damages pursuant to Clause 7.13, the
              period of twenty (20) years shall commence from the date on which
              KPLC begins to pay such damages.

2.3     EXTENSION: The Term may be extended, subject to agreement in writing by
        the Parties to such extension at least twelve (12) months prior to its
        expiry, and on such terms as the Parties shall agree.

2.4     REGULATORY APPROVALS: The Parties acknowledge that the original Power
        Purchase Agreement dated 5 November 1998, the First Supplemental
        Agreement dated 21 July 2000, the Second Supplement Agreement dated 17
        April 2003, and this Amended and Restated Power Purchase Agreement were
        each approved by the Electricity Regulatory Board in accordance with the
        legal requirements, on diverse dates, as per the approvals attached
        hereto as Schedule 11.

CLAUSE 3: CONDITIONS PRECEDENT AND SECURITY

3.1     CONDITIONS: Except for the Parties' respective obligations in Clauses
        3.2, 14.3 and 16.7 or as otherwise provided herein, the Parties'
        obligations hereunder shall commence on the date (the "Effective Date")
        on which the last of the conditions in Parts A and B of Schedule 6 have
        been satisfied in accordance with Clause 3.2.

3.2     SELLER'S CONDITIONS: The Seller shall use all reasonable endeavours to
        satisfy the conditions in Part A of Schedule 6 and to comply with the
        condition in Part B of Schedule 6 by the Target Effective Date and KPLC
        shall use all reasonable endeavours to assist the Seller in obtaining
        the Authorisations specified in paragraph (ii) of Part A of Schedule 6,
        provided that:

        3.2.1 if the Seller fails to achieve the Target Effective Date the
              Seller shall continue to use all reasonable endeavours to satisfy
              the conditions in Part A of Schedule 6 and to comply with the
              condition in Part B of Schedule 6 by the Long Stop Effective Date.

        3.2.2 the Seller shall diligently attempt to obtain all Authorisations
              which diligence shall include:

              (i)  full and timely compliance with all procedural requirements
                   relating to the issue of such Authorisation, and with all
                   Legal Requirements which relate to the activities of the
                   Seller within the Republic of Kenya; and

              (ii) pursuing all reasonably available procedures for appealing
                   against or challenging the grounds upon which such
                   Authorisation is not issued; and

        3.2.3 the Seller shall use all reasonable endeavours to enter into the
              Site Agreement.

3.3     NON-SATISFACTION: If any of the conditions referred to in Part A of
        Schedule 6 has not been satisfied, or the condition referred to in Part
        B of Schedule 6 has not been complied with, by the Long Stop Effective
        Date other than by reason of a breach by


                                       14



        the Seller of its obligations under Clause 3.2 then either Party may
        terminate this Agreement.

3.4     NON-SATISFACTION INVOLVING A BREACH: If any of the conditions referred
        to in Par A of Schedule 6 has not been satisfied by the Long Stop
        Effective Date or any of the conditions referred to in Part B of
        Schedule 6 has not been complied with by reason of a breach by the
        Seller of its obligations under Clause 3.2 then KPLC may terminate this
        Agreement.

3.5     BID SECURITY:

        (a)  On the Signature Date, the Seller shall provide to KPLC the Bid
             Security. The Bid Security shall be effective from the Signature
             Date to the earlier of the date on which the Seller provides to
             KPLC the Construction Bond and the date on which the Parties agree
             or an Expert determines, in accordance with Clause 5, that the
             Reservoir cannot support a Plant with a Contracted Plant Capacity
             of at least twenty-eight (28) MW.

        (b)  If the Effective Date does not occur on or before the Long Stop
             Effective Date:

             (i)  due to a failure under Clause 3.2 caused by the Seller not
                  diligently attempting to obtain such Authorisation; or

             (ii) due to a failure by the Seller to use reasonable endeavours by
                  the Long Stop Effective Date to satisfy the Conditions
                  Precedent in Part A of Schedule 6,

             then KPLC may take all steps necessary to obtain payment of the
             full amount of the Bid Security.

        (c)  If the Seller:

             (i)   has not commenced the Appraisal Works by the Long Stop
                   Appraisal Works Start Date; or

             (ii)  has failed to achieve the Early Generation Commercial
                   Operation Date by the Early Generation Long Stop Commercial
                   Operation Date; or

             (iii) has failed to provide KPLC with the Construction Bond within
                   twenty-eight (28) days of the Parties having agreed or an
                   Expert having determined, in accordance with Clause 5, that
                   the Reservoir can support a Plant with a Contracted Capacity
                   of at least twenty-eight (28) MW,

             then KPLC may take all steps necessary to obtain payment of the
             full amount of the Bid Security.

        (d)  If KPLC does not claim payment of the full amount of the Bid
             Security pursuant to Clauses 3.4(b) and 4.5(c), the Bid Security
             will be returned by KPLC to the Seller on the later of the date on
             which the Seller provides to


                                       15



             KPLC the Construction Bond and the date the Parties agree or an
             Expert determines, in accordance with Clause 5, that the Reservoir
             cannot support a Plant with a Contracted Plant Capacity of at least
             twenty-eight (28) MW.

3.6     SATISFACTION OF REQUIREMENTS

        The Parties hereby acknowledge that, as of the date hereof, all of the
        obligations, requirements and arrangements under Clauses 3.1 though 3.5
        above have been satisfied in full.

3.7     CONSTRUCTION BOND

        (a)  Contemporaneous with the issuance of the initial Letter of Credit
             (as defined in the Olkaria III Project Security Agreement) to the
             Seller, the Seller shall provide to KPLC the Construction Bond.

        (b)  Unless payment thereunder is earlier demanded by KPLC, the
             Construction Bond shall continue in force until the issue by the
             independent engineer of a certificate under Clause 7.10 in which
             event the Construction Bond shall lapse and shall be returned to
             the Seller and KPLC shall make no demand thereon.

        (c)  If the Seller fails to achieve the Full Commercial Operation Date
             by the Long Stop Full Commercial Operation Date then KPLC may take
             all steps necessary to obtain payment of the full amount of the
             Construction Bond.

        (d)  In the event that the Seller does not provide to KPLC the
             Construction Bond pursuant to Clause 3.7(a), KPLC shall:

             (i)  Be entitled to withhold the monthly Capacity Payments due to
                  the Seller equal to a sum of seven hundred and fifty thousand
                  United States Dollars (US$750,000) ("Construction Security");

             (ii) Deposit the Construction Security in an interest bearing
                  account at a bank agreed between the Parties acting reasonably
                  where the Construction Security shall be held until either the
                  issue by the independent engineer of a certificate under
                  Clause 7.10 in which even the Construction Security shall be
                  returned with any interest which has accrued on that account
                  to the Seller, or if the Seller fails to achieve the Full
                  Commercial Operation Date by the Long Stop Full Commercial
                  Operation Date KPLC shall be entitled to retain the
                  Construction Security net of all interest received by KPLC.


                                       16



CLAUSE 4: SITE

4.1     SITE AGREEMENT: Prior to the Effective Date the Seller shall enter into
        the Site Agreement.

4.2     LAND OWNED BY GOK: Pursuant to the Site Agreement, the Seller shall
        procure from the Governmental Authority an interest in or over the land
        owned by the Governmental Authority within the Licence Area as is
        necessary for the Seller to meet its obligations under this Agreement
        including the construction of the Early Generation Facility and the
        Plant and the conduct of the Appraisal Works.

4.3     LAND NOT OWNED BY GOK: In the event that the Seller requires an interest
        in or over land not owned by the Governmental Authority within the
        Licence Area, the Seller shall first diligently attempt to procure such
        interest from the owner of the land. For the purposes of this Clause
        4.3, "diligently" shall include pursuing all reasonably available
        procedures for obtaining such interest, including the offer of a rent or
        purchase price which a person carrying out the Seller's activities would
        reasonably expect to pay for such an interest. If the Seller can
        demonstrate to GOK that such interest cannot be so procured within one
        hundred and twenty (120) days, the Seller shall pursuant to the Site
        Agreement require GOK to acquire such land for the Seller at the
        Seller's cost. The Seller shall forthwith procure from the owner of the
        land an interest in or over the land as is necessary for it to meet its
        obligations under this Agreement.

4.4     SELLER'S OBLIGATIONS: The Seller shall perform is obligations under and
        observe all the terms of all agreements entered into between the Seller
        and GOK or the Seller and other owners of land for the purposes of this
        Clause 4 (collectively referred to as "Land Agreements"). The Seller
        shall not:

        (i)   terminate or permit the termination of the Land Agreements;

        (ii)  in any material respect depart from, or waive or fail to enforce
              any rights it may have under the Land Agreements;

        (iii) enter into any agreement, document or arrangement which would
              materially affect the interpretation or application of the Land
              Agreements

        unless the relevant document or proposed course of action has been
        notified in writing to KPLC and there has been no objection by KPLC. For
        the purposes of this Clause 4, the failure by the Seller to enter into a
        Land Agreement or the termination of a Land Agreement shall not
        constitute Force Majeure.

4.5     SATISFACTION OF REQUIREMENTS:

        The Parties hereby acknowledge that, as of the date hereof, all of the
        obligations, requirements and arrangements under Clauses 4.1 through 4.3
        above have been satisfied in full.


                                       17





CLAUSE 5: GEOTHERMAL RESERVOIR APPRAISAL AND DEVELOPMENT

5.1     THE SELLER'S OBLIGATION: The Seller shall carry out the Appraisal Works
        in accordance with the Appraisal Programme and Prudent Operating
        Practice.

5.2     MONITORING: KPLC shall be entitled at its own cost to monitor the
        progress of the Appraisal Works and the Seller will provide such access,
        information and assistance to KPLC as KPLC reasonably requires for it to
        carry out such function including without limitation providing
        reasonable notice of the spudding of wells, copies of geo-scientific and
        well log data (and interpretative work in relation thereto).

5.3     CONSTRUCTION PROGRAMME: The Seller may, before the end of the Appraisal
        Period, in the light of the results of the Appraisal Works provide to
        KPLC a revised Construction Programme. Any revised Construction
        Programme must provide for the Full Commercial Operation Date to occur
        on or before the Required Full Commercial Operation Date.

5.4     CONTRACTED PLANT CAPACITY: The Seller may, in the light of the results
        of the Appraisal Works, at any time before the end of the Appraisal
        Period, by notice to KPLC increase the Contracted Plant Capacity to an
        amount, not exceeding one hundred (100) MW or decrease the Contracted
        Plant Capacity to an amount, not less than twenty-eight (28) MW, as can,
        subject to the installation of necessary Steam Field Facilities, be
        supported by the Reservoir on the basis that:

        (a) the Plant is operated at ninety-two per cent (92%) of the proposed
            revised Contracted Plant Capacity throughout the Term; and

        (b) at any time the Reservoir can sustain a continuous steam flow of at
            least one hundred and twenty per cent (120%) of the steam flow
            required for the Plant to operate continuously, subject to Planned
            Maintenance, at one hundred per cent (100%) of the revised
            Contracted Plant Capacity; and

        (c) the steam flow required by Olkaria I to generate forty-five (45) MW
            and the steam flow required by Olkaria II to generate sixty-four
            (64) MW will not be significantly affected.

        The Seller's notice under this Clause 5.4 shall be accompanied by a
        detailed report which provides the Seller's justification for the
        increased Contracted Plant Capacity and contains all relevant supporting
        evidence and data.

5.4A    EXPANSIONS OF OLKARIA I AND OLKARIA II: KPLC shall not purchase more
        than forty-five (45) MW from Olkaria I or more than sixty-four (64) MW
        from Olkaria II if the steam flow for the Plant would be materially
        affected. KPLC shall notify the Seller if it wishes to purchase more
        than forty-five (45) MW from Olkaria I or more than sixty-four (64) MW
        from Olkaria II and shall use reasonable endeavours to procure for the
        Seller a detailed report and relevant supporting evidence and data as to
        the steam flow and whether it would be materially affected. In the event
        of a dispute the matter may be referred by either Party to an Expert who
        shall determine whether the steam flow for the Plant would be materially
        affected.



                                       18





5.4B    CO-ORDINATING COMMITTEE: The Parties acknowledge that it is in their
        interests to share information regarding the geothermal resource at
        Olkaria and recognising this interest the Parties shall participate in a
        co-ordinating committee to facilitate the exchange of information.

5.5     DISPUTE OVER REVISED CONTRACTED PLANT CAPACITY: If KPLC disputes the
        proposed revised Contracted Plant Capacity notified by the Seller
        pursuant to Clause 5.4 it may notify the Seller within twenty-eight (28)
        days of the Seller's notice of such dispute and thereafter the matter
        may be referred by either Party to an Expert who shall determine whether
        the proposed revised Contracted Plant Capacity can be supported on the
        basis specified in Clause 5.4. In the event that the matter is referred
        to an Expert, the Required Full Commercial Operation Date and the Long
        Stop Full Commercial Operation Date shall be extended by the period
        during which the Expert is making his determination.

5.6     EFFECTIVE DATE OF CHANGE: A change in the Contracted Plant Capacity
        shall take effect after the expiry of twenty-eight (28) days following
        the Seller's notice under Clause 5.4 provided that KPLC has not served a
        notice to the Seller pursuant to Clause 5.5. If KPLC so serves a notice
        a change in the Contracted Plant Capacity shall take effect from the
        date of the Expert's determination provided that the Expert determines
        that the Seller's proposed revised Contracted Plant Capacity can be
        supported as aforesaid.

5.7     LIMITED RESERVOIR CAPACITY: The Seller may, at any time after completion
        of the Appraisal Programme and before the end of the Appraisal Period,
        serve a notice of limited reservoir capacity ("Notice of Limited
        Reservoir Capacity") on KPLC if the Seller reasonably believes, in the
        light of the results of the Appraisal Works, that the Reservoir cannot,
        on the basis of the assumptions referred to in Clause 5.4, support a
        Contracted Plant Capacity of at least twenty-eight (28) MW throughout
        the Term. The Seller's notice under this Clause 5.7 shall be accompanied
        by a detailed report which provides the Seller's justification for its
        belief that the Reservoir cannot support a Contracted Plant Capacity of
        at least twenty-eight (28) MW and contains all relevant supporting
        evidence and data.

5.8     DISPUTE OVER NOTICE OF LIMITED RESERVOIR CAPACITY: KPLC may within 2
        months of receiving a notice from the Seller under Clause 5.7 serve a
        notice on the Seller if it disputes the Notice of Limited Reservoir
        Capacity, in which event the matter shall be referred to an Expert who
        shall determine the Contracted Plant Capacity which can be supported by
        the Reservoir throughout the Term. In the event that the matter is
        referred to an Expert, the Required Full Commercial Operation Date and
        the Long Stop Full Commercial Operation Date shall be extended by the
        period during which the Expert is making his determination.

5.9     FAILURE TO AGREE: If KPLC does not serve a notice under Clause 5.8 or,
        following such a notice, the Expert determines that the Reservoir cannot
        support a Contracted Plant Capacity of at least twenty-eight (28) MW
        throughout the Term, the Parties shall meet and discuss whether they can
        agree terms for the construction of a Plant with a Contracted Plant
        Capacity greater than the Contracted Early Generation Capacity but less
        than twenty-eight (28) MW. If the Parties have not reached agreement by
        the later of six (6) months after the service of the Seller's notice
        under



                                       19





        Clause 5.7 and two (2) months after the date of the Expert's
        determination, the Seller shall continue to operate the Early Generation
        Facility and KPLC shall continue to meet its payment and other
        obligations in accordance with this Agreement.

5.10    GEOTHERMAL RESERVOIR DEVELOPMENT I: The Seller shall, in accordance with
        Prudent Operating Practice, install, maintain and operate such Steam
        Field Facilities as are necessary to ensure that at any time, prior to
        the Early Generation Cessation Date or throughout the Term (as the case
        may be), the Reservoir can sustain a continuous steam flow of at least
        one hundred and twenty per cent (120%) of the steam required for the
        Early Generation Facility to operated continuously subject to Planned
        Maintenance, at one hundred per cent (100%) of the Contracted Early
        Generation Capacity.

5.10A   GEOTHERMAL RESERVOIR DEVELOPMENT II: The Seller shall, in accordance
        with Prudent Operating Practice, install, maintain and operate such
        Steam Field Facilities as are necessary to ensure that at any time,
        throughout the Term the Reservoir can sustain a continuous steam flow of
        at least one hundred and twenty per cent (120%) of the steam required
        for the Plant to operated continuously subject to Planned Maintenance,
        at one hundred per cent (100%) of the Contracted Plant Capacity provided
        that if the Reservoir cannot sustain such steam flow, the Seller shall
        forthwith notify KPLC and the Parties shall meet in good faith to agree
        new criteria of the steam flow required and in the absence of such
        agreement, the matter shall be referred to an Expert for determination.

5.11    STEAMFIELD APPRAISAL RECORDS: Any notice given by the Seller under
        Clause 5.4 or Clause 5.7 shall be accompanied by all records relating to
        the Appraisal Works.

5.12    SATISFACTION OF REQUIREMENTS:

        The Parties hereby acknowledge that, as of the date hereof, all of the
        obligations, requirements and arrangements under Clauses 5.1 through 5.9
        and under Clause 5.11 above have been satisfied in full, and the
        Contracted Plant Capacity was determined pursuant to the Appraisal Works
        and the Appraisal Programme at 48 MW.




CLAUSE 6: CONSTRUCTION

6.1     SELLER'S RESPONSIBILITY: The Seller shall design, furnish, construct and
        install in accordance with the Construction Programme:

        (a) the Early Generation Facility and the Plant so as to comply in all
            material respects with the Functional Specification, the System
            Characteristics and the relevant provisions of Part B of Schedule 2;
            and

        (b) the Transmission Interconnector so as to comply in all material
            respects with the specification for such Transmission Interconnector
            in Part B of Schedule 2 and the System Characteristics.

6.1A    EARLY GENERATION CESSATION DATE: Prior to commencement of the Plant
        Commercial Operations Test, the Seller shall notify KPLC of a date on
        which the Early Generation Facility shall cease to be operated at the
        Early Generation Site ("Early Generation Cessation Date"). From the
        Early Generation Cessation Date, the Seller



                                       20



        shall keep KPLC informed of the Seller's progress in installing the
        Early Generation Facility at the Site. The Parties acknowledge that the
        Seller shall be unable to deliver electricity to KPLC for the period
        commencing from the Early Generation Cessation Date to the date of
        commencement of the Plant Commercial Operations Tests, Seller shall have
        no obligation to produce energy or make capacity available during this
        period, and KPLC shall not be required to make any payments to the
        Seller in respect to this period.

6.2     KPLC'S RESPONSIBILITY: KPLC shall design, furnish, construct and install
        KPLC's Connection Facilities in accordance with the Construction
        Programme and so as to comply in all material respects with the
        specification for such facilities as specified in Part B of Schedule 2.

6.3     INFORMATION: Each Party shall keep the other Party informed of the
        progress of the design, furnishing, construction and installation of the
        facilities to be installed by it pursuant to Clause 6.1 or 6.2, and
        every months shall provide a written progress report in respect thereof.

6.4     LOCAL CONTRACTS: The Seller shall, where possible, award contracts to
        contractors with existing operations in Kenya and suppliers of materials
        and services while existing operations in Kenya provided that the
        quality, delivery times, costs, reliability and other terms are
        comparable to those offered by foreign contractors and/or suppliers.

6.5     MONITOR PROGRESS: The Seller shall:

        (a) ensure that KPLC and any representative appointed by KPLC are
            afforded reasonable access to the Early Generation Site and the Site
            upon giving the Seller reasonable notice provided that such access
            does not materially interfere with the construction works or expose
            any person on the Early Generation Site or the Site to any danger;

        (b) make available for inspection at the Early Generation Site and the
            Site copies of all plans and designs other than any proprietary
            information of the Seller or any sub-contractor in relation to the
            construction or any part thereof; and

        (c) within six months of the Early Generation Commercial Operation Date
            and the Full Commercial Operation Date, supply KPLC with one set of
            reproducible copies and five sets of white print copies (or
            equivalent) of all "as built" plans and designs required for the
            operation and maintenance of the Early Generation Facility and the
            Plant.

6.6     DISCLAIMER: The Seller:

        (a) accepts that any engineering review or inspection conducted by KPLC
            pursuant to Clause 6.5 is solely for its own information and
            accordingly by conducting such review or inspection KPLC makes no
            representation as to the engineering soundness of the Early
            Generation Facility and the Plant;


                                       21



        (b) shall in no way represent to any third party that, as a result of
            any review or inspection by KPLC, KPLC is responsible for the
            engineering soundness of the Early Generation Facility and the
            Plant; and

        (c) shall, subject to the other provisions of this Agreement, be solely
            responsible for the economic and technical feasibility, operational
            capacity and reliability of the Early Generation Facility and the
            Plant.

6.7     FAILURE TO ACHIEVE FULL COMMERCIAL OPERATION DATE BY REQUIRED FULL
        COMMERCIAL OPERATION DATE: If the Full Commercial Operation Date has not
        occurred by the Required Full Commercial Operation Date (otherwise than
        due to Force Majeure of default by KPLC) then:

        (a) for each day occurring after the date which is 14 (fourteen) days
            after the Required Full Commercial Operation Date and before the
            Full Commercial Operation Date the Seller shall pay monthly, in
            arrears, to KPLC the Daily Liquidated Damages Sum up to a total
            aggregate sum of three million United States Dollars (US$3,000,000);
            and

        (b) the Seller shall have no further liability to KPLC in respect of
            such delay and payment by the Seller to KPLC under this Clause 6.7
            shall constitute KPLC's sole and exclusive remedy for the Seller's
            failure to achieve the Required Full Commercial Operation Date.

6.8     LONG STOP DATES: If, other than by reason of Force Majeure or default by
        KPLC:

        (a) the Seller has not commenced the Appraisal Works by the Long Stop
            Appraisal Works Start Date; or

        (b) the Seller failed to achieve the Early Generation Commercial
            Operation Date by the Early Generation Long Stop Commercial
            Operation Date; or

        (c) where, pursuant to the results of the Appraisal Works under Clause
            5, it has been determined that the Reservoir can support a
            Contracted Plant Capacity of at least twenty-eight (28) MW, the
            Seller has not commenced construction of the Plant by the Long Stop
            Construction Date; or

        (d) where, pursuant to the results of the Appraisal Works under Clause
            5, it has been determined that the Reservoir can support a
            Contracted Plant Capacity of at least twenty-eight (28) MW, the Full
            Commercial Operation Date has not occurred by the Long Stop Full
            Commercial Operation Date,

        KPLC may terminate this Agreement by notice to the Seller within two (2)
        months of the occurrence of the relevant Long Stop Date. Such
        termination shall be without prejudice to any rights accrued due to
        either party at the date of termination.

6.9     SATISFACTION OF REQUIREMENT: The Parties hereby acknowledge that as of
        the date hereof, all of the obligations, requirements and arrangements
        under Clauses 6.1(a), 6.3, 6.5, 6.8(a), 6.8(b) and 6.8(c) with respect
        to the Appraisal Works, the Early


                                       22



        Generation Facility, and the commencement of construction of the Plant
        have been satisfied in full.



CLAUSE 7: COMMISSIONING AND TESTING

7.1     THE SELLER'S OBLIGATIONS: The Seller shall, subject to Clause 7.2, test
        and Commission the Early Generation Facility and the Plant in accordance
        with the Commissioning and testing procedures (including test tolerances
        and criteria) set out in Part A of Schedule 4 and the further procedures
        agreed or determined pursuant to Clause 7.5 and 7.5A and in accordance
        with the Prudent Operating Practice.

7.2     TRANSMISSION INTERCONNECTOR COMMISSIONING AND TESTING: The Seller shall
        test and Commission the Transmission Interconnector and other facilities
        specified in Part B of Schedule 2 in accordance with the Commissioning
        and testing procedures (including test tolerances and criteria) set out
        in Part A of Schedule 4 and the further procedures agreed or determined
        pursuant to Clause 7.5 and 7.5A and in accordance with the Prudent
        Operating Practice. The Seller shall before Commissioning of the Plant
        commences procure that the certificate of an independent engineer,
        approved by KPLC, is issued, addressed to KPLC and the Seller,
        certifying that the testing of the Transmission Interconnector has been
        satisfactorily completed and that it is available for commercial
        operation.

7.3     NOTIFICATIONS: The Seller will give KPLC not less than thirty (30) days'
        notice of the date of commencement of the respective Commissioning of
        the Transmission Interconnector, the Early Generation Facility and the
        Plant and not less than fifteen (15) days' notice of the date of the
        respective testing (except for routine construction tests) of the
        Transmission Interconnector, the Early Generation Facility and the
        Plant, provided that the Seller may postpone any such date by giving
        KPLC not less than the seven (7) days notice of the postponed date.

7.4     KPLC ATTENDANCE: KPLC shall have the right to attend each occasion on
        which a test of the Transmission Interconnector, the Early Generation
        Facility and the Plant is being conducted, and to witness the test, and
        to receive within fifteen (15) days after the test a copy of the test
        reports with shall be prepared by the Seller.

7.5     DETAILED PROCEDURES I: The Parties shall, not later than ninety (90)
        days before the Early Generation Commissioning Date, agree (or failing
        such agreement an Expert shall determine) detailed procedures consistent
        with best international practice for testing and Commissioning the Early
        Generation Facility in accordance with, and consistent with, Part A of
        Schedule 4.

7.5A    DETAILED PROCEDURES II: The Parties shall, not later than ninety (90)
        days before the Plant Commissioning Date, agree (or failing such
        agreement an Expert shall determine) detailed procedures consistent with
        best international practice for testing and Commissioning the
        Transmission Interconnector and the Plant (and Units) in accordance
        with, and consistent with Schedules 2 and 4.

7.6     KPLC'S TRANSMISSION INTERCONNECTOR AND KPLC'S CONNECTION FACILITIES:
        KPLC shall complete the installation, testing and Commissioning of
        KPLC's Transmission Interconnector no later than sixteen (16) months
        after the Effective Date. KPLC shall



                                       23





        complete the installation, testing and Commissioning of KPLC Connection
        Facilities no later than seventeen (17) months and two weeks after the
        Signature Date.

7.7     KPLC COOPERATION: KPLC will cooperate with the Seller so as to enable
        the Seller to Commission and test the Transmission Interconnector and
        each Unit in accordance with this Clause 7 and in particular will
        authorise connection to KPLC's System and despatch the Unit to the
        extent reasonably required by the Seller for such purpose and in
        accordance with the procedures in Part A of Schedule 4 and agreed or
        determined under Clauses 7.5 and 7.5A.

7.8     RETESTING: Where any test (including a test arranged under this Clause)
        of the Transmission Interconnector or of a Unit not completed
        satisfactorily in accordance with Schedule 4 the Seller may arrange a
        further test by giving KPLC not less than seventy-two (72) hours notice
        and such test shall be conducted by the Seller in accordance with the
        foregoing provisions of this Clause.

7.9     EARLY GENERATION COMMERCIAL OPERATIONS TESTS: Following completion of
        the Unit Commercial Operations Tests of the Early Generation Facility,
        the Seller shall conduct the Early Generation Commercial Operations
        Tests. Upon satisfactory completion of the Early Generation Facility
        Operations Tests, the Seller shall procure that the certificate of an
        independent engineer, approved by KPLC, is issued, addressed to KPLC and
        the Seller, certifying that the Early Generation Facility's testing has
        been so completed and that the Early Generation Facility is available
        for commercial operation. The Early Generation Commercial Operation Date
        shall be the date occurring immediately after the day on which the Early
        Generation Facility has passed the Early Generation Commercial
        Operations Tests.

7.10    PLANT COMMERCIAL OPERATIONS TESTS: Following completion of the Unit
        Commercial Operations Tests, conducted after the reinstallation of the
        Early Generation Facility Units at the Site (if necessary), the Seller
        shall conduct the Plant Commercial Operations Tests. Upon satisfactory
        completion of the Plant Commercial Operations Tests, the Seller shall
        procure that the certificate of an independent engineer, approved by
        KPLC, is issued, addressed to KPLC and the Seller, certifying that the
        Plant's testing has been so completed and that the Plant is available
        for full commercial operation. The Seller shall upon issue of the
        certificate notify KPLC of a date (the "Full Commercial Operation Date")
        being a date no later than twenty-one (21) days after the date of the
        notice. The Seller shall not notify KPLC of the Full Commercial
        Operation Date until such time as the Early Generation Facility has been
        reinstalled and the Plant has passed the Plant Commercial Operations
        Tests.

7.11    PAYMENT DURING EARLY GENERATION FACILITY TESTING: KPLC shall pay Energy
        Charges to the Seller in accordance with Part A of Schedule 5 for all
        Net Electrical Output supplied by the Early Generation Facility after
        the Early Generation Commissioning Date and prior to the Early
        Generation Commercial Operation Date.

7.11A   PAYMENT DURING PLANT TESTING: KPLC shall pay Energy Charges to the
        Seller in accordance with Part B of Schedule 5 for all Net Electrical
        Output supplied by the Plant prior to the Full Commercial Operation
        Date.



                                       24





7.12    TRANSFER OF TRANSMISSION INTERCONNECTOR: Upon the issue of the
        certificate of the independent engineer referred to in Clause 7.2 the
        Seller shall transfer to KPLC all right, title and interest in the
        Transmission Interconnector, all technical drawings, data and material
        related to it and all intellectual property rights (whether such rights
        be registered, unregistered or registrable) necessary for KPLC to enjoy
        free and unencumbered use of it, free of all charges and encumbrances
        together with the benefit of any designers' and manufacturers'
        warranties.

7.13    KPLC FAILURE TO COMPLETE KPLC'S CONNECTION FACILITIES OR KPLC'S
        TRANSMISSION INTERCONNECTOR: In the event that the Seller is unable to
        undertake the Commissioning and/or testing of the Plant solely due to a
        failure by KPLC to complete its facilities by the Required Early
        Generation Commercial Operation Date or the Required Full Commercial
        Operation Date KPLC shall pay to the Seller monthly (and pro-rated for
        any proportion of the month), in arrears, an amount equal to the
        Capacity Payment based on the Contracted Early Generation Capacity or
        Contracted Plant Capacity (as the case may be).

7.14    SELLER'S FAILURE TO COMPLETE THE TRANSMISSION INTERCONNECTOR OR THE
        INTERCONNECTION OF THE EARLY GENERATION FACILITY: For the avoidance of
        doubt, in the event that the Seller does not undertake the Commissioning
        and/or testing of one or more Units due to its failure to complete the
        connection to the Early Generation Facility or the Transmission
        Interconnector in accordance with KPLC design standards and criteria
        KPLC shall not be liable for the payment of the Capacity Payments and
        Energy Charges and Clauses 6.7 and 6.8 shall apply until such time as
        the Seller has completed the interconnection to the Early Generation
        Facility shall not be liable for the payment of the Capacity Payments
        and Energy Charges and Clauses 6.7 and 6.8 shall apply until such time
        as the Seller has completed the interconnection to the Early Generation
        Facility or the Transmission Interconnector (as the case may be).

7.15    SATISFACTION OF REQUIREMENTS:

        The Parties hereby acknowledge that as of the date hereof, all of the
        obligations, requirements and arrangements under Clauses 7.1, 7.3, 7.4,
        7.5, 7.6, 7.7 and 7.9 with respect to the Early Generation Facility,
        including the KPLC's Transmission Interconnector, have been satisfied in
        full.


CLAUSE 8: OPERATING AND DESPATCH PROCEDURES

8.1     OPERATION: The Seller shall during the Term operate the Early Generation
        Facility and Plant in a manner consistent with Prudent Operating
        Practice, in compliance with the Despatch Instructions and on the basis
        of the System Characteristics.

8.2     NOTIFICATION: In accordance with the Operating and Despatch Procedures
        and any procedures agreed or specified by KPLC under Clauses 8.4 and
        8.5, the Seller shall keep KPLC informed by regular daily declarations,
        together with prompt declarations of any changes, of the Available Early
        Generation Capacity and Available Plant Capacity (as the case may be)
        and any impairment of the Early Generation Facility's or the Plant's
        Operating Characteristics (as the case may be) provided that during
        Planned Maintenance of the Early Generation Facility or the Plant, the
        Early


                                       25



        Generation Facility or the Plant (as the case may be) shall be deemed to
        be declared unavailable unless the Seller makes a contrary declaration.

8.3     DESPATCH INSTRUCTIONS: KPLC shall issue Despatch Instructions consistent
        with the Functional Specification, including the System Characteristics,
        prevailing declarations of Availability and any impairment of Operating
        Characteristics and despatch constraints, and in accordance with the
        Operating and Despatch Procedures and any procedures agreed under Clause
        8.4 and Clause 8.5, and shall seek to ensure that KPLC's System complies
        with and does not deviate from the System Characteristics.

8.4     FURTHER PROCEDURES I: The Parties shall not later than the Early
        Generation Commissioning Date, agree in respect of the Early Generation
        Facility (in accordance with and consistent with the Operating and
        Despatch Procedures and all other terms of this Agreement) such further
        procedures as shall be necessary in accordance with Prudent Operating
        Practice for the despatch of the Early Generation Facility and
        operational communications between the Parties. Any further procedures
        not agreed by the Parties by the Early Generation Commercial Operation
        Date shall be specified by KPLC in accordance with Prudent Operating
        Practice.

8.5     FURTHER PROCEDURES II: The Parties shall, not later than the Plant
        Commissioning Date agree in respect of the Plant (in accordance with and
        consistent with the Operating and Despatch Procedures and all other
        terms of this Agreement) such further procedures (if any) as shall be
        necessary in accordance with Prudent Operating Practice for the despatch
        of the Plant and operational communications between the Parties. Any
        further procedures not agreed by the Parties by the Full Commercial
        Operation Date shall be specified by KPLC in accordance with Prudent
        Operating Practice.

8.6     OVER-GENERATION: In the event that the Seller over a period of four (4)
        or more successive Settlement Periods delivers to KPLC electricity in
        excess of the Despatch Instructions, KPLC may by notice require the
        Seller to comply with Despatch Instructions and if such excess delivery
        continues, the Seller shall notwithstanding the provisions of Clause
        10.2 not be entitled to receive the Energy Charges in respect of any
        excess delivery.

8.7     UNDER-GENERATION: In the event that the Seller having failed to notify
        KPLC of a reduction in Declared Capacity delivers to KPLC electricity
        over a period of four (4) or more successive Settlement Periods which is
        less than the quantity required by the Despatch Instructions
        ("Under-Generation"), KPLC may by notice require the Seller to remedy
        such under-generation within the following two (2) Settlement Periods
        (i.e. within one (1) hour) and to comply with the Despatch Instructions.
        If the Seller continues such Under-Generation, for subsequent Settlement
        Periods in which under-generation is continuing the Seller's Declared
        Capacity shall be deemed to equal to twice the Net Electrical Output.

8.8     NOTICE: Any notice given by KPLC under Clauses 8.6 and 8.7 shall be
        given in writing and delivered by facsimile to the Seller at the
        address, and marked for the attention of the person, specified in
        Schedule 8 or such other address or person from time to time designated
        by the Seller and such notice shall be deemed to be received


                                       26



        upon confirmation of uninterrupted transmission by a transmission report
        provided that such notice shall be confirmed by letter sent by hand or
        post, but without prejudice to the original facsimile notice.



CLAUSE 9: MAINTENANCE AND REPAIR

9.1     THE SELLER'S OBLIGATION I: The Seller shall maintain and repair the
        Plant in accordance with Prudent Operating Practice during the Operating
        Period.

9.1A    THE SELLER'S OBLIGATIONS II: The Seller shall maintain and repair the
        Early Generation Facility in accordance with Prudent Operating Practice
        from the Early Generation Commissioning Date for the Term or until the
        Early Generation Cessation Date or the Full Commercial Operation Date,
        whichever is the earlier, unless this Agreement is terminated earlier.

9.2     PLANNED MAINTENANCE: The Seller shall be entitled to withdraw each Unit
        from operation for maintenance and inspection each year for periods not
        exceeding those specified in Schedule 3.

9.3     PLANNED MAINTENANCE PROGRAMME: The programme of Planned Maintenance for
        each Operating Year shall be established as follows:

        (a) the Seller shall not later than ninety (90) days before the start of
            each Operating Year submit to KPLC proposed dates for Planned
            Maintenance in that year;

        (b) KPLC may within thirty (30) days after receiving the Seller's
            proposed dates notify the Seller of alternative dates which KPLC
            prefers, in which case the Parties shall consult and the Seller
            shall use reasonable endeavours to accommodate KPLC's proposal;

        (c) not less than thirty (30) days before the start of the relevant
            Operating Year the Seller shall issue a final programme (including
            dates) for Planned Maintenance in accordance with the agreement
            reached by consultation under Clause 9.3(b) provided that where no
            agreement was reached then KPLC's alternative dates shall prevail,
            to the extent that such alternative dates do not result in the
            Seller incurring unreasonable costs;

        (d) the scheduled maintenance allowance shall be calculated in
            accordance with Part A or Part B of Schedule 3 (as the case may be),
            using the Planned Maintenance schedule agreed pursuant to Clauses
            9.3(a), (b) and (c).

9.4     CHANGES TO PROGRAMME: The Parties shall cooperate and use their
        reasonable endeavours to accommodate any reasonable request by either
        Party to reschedule any Planned Maintenance an any Operating Year.

9.5     MAINTENANCE OUTAGES: Without prejudice to Clause 9.1 and subject to
        applicable notification requirements under the Operating and Despatch
        Procedures, nothing in this Agreement shall oblige the Seller to take a
        Unit out of operation at the start of the



                                       27



        relevant period specified in the programme for Planned Maintenance nor
        prevent the Seller from returning a Unit to operation before the end of
        such period.

9.6     OTHER OUTAGES: Nothing in this Agreement shall prevent the Seller from
        carrying out maintenance or repair of the Early Generation Facility or
        the Plant (and taking a Unit out of operation for this purpose) at times
        other than during Planned Maintenance where such maintenance or repair
        cannot, in accordance with Prudent Operating Practice, be deferred to
        the next scheduled Planned Maintenance or upon the occurrence of any
        outage.

9.7     KPLC MAINTENANCE: KPLC shall in accordance with Prudent Operating
        Practice maintain and repair KPLC's Connection Facilities, and shall
        seek to coordinate the timing of such maintenance or repair with the
        Seller's Planned Maintenance.



9.8     REVISION TO CONTRACTED EARLY GENERATION CAPACITY: From the Early
        Generation Commercial Operation Date and prior to the Full Commercial
        Operation Date and not less than once in every period of twelve (12)
        months the Seller shall conduct a Contracted Early Generation Capacity
        Test on the Early Generation Facility. Following a Contracted Early
        Generation Capacity Test the Seller may revise the Contracted Early
        Generation Capacity to accord with the results of such test provided
        that the Contracted Early Generation Capacity of the Early Generation
        Facility may not be less than the Contracted Early Generation Capacity
        at the Signature Date.

9.8A    REVISION TO CONTRACTED PLANT CAPACITY: After the Full Commercial
        Operation Date and not less than once in every period of twelve (12)
        months the Seller shall conduct a Contracted Plant Capacity Test on the
        Plant. Following a Contracted Plant Capacity Test the Seller may revise
        the Contracted Plant Capacity to accord with the results of such test
        provided that the Contracted Plant Capacity may not be less than ninety
        per cent (90%) of the Contracted Plant Capacity agreed at the end of the
        Appraisal Period, nor greater than one hundred and ten per cent (110%)
        of that amount, provided that the Reservoir can sustain the required
        steam flow. If the Reservoir cannot sustain such steam flow, the Seller
        shall forthwith notify KPLC and the Parties shall meet in good faith to
        agree new criteria of the steam flow required and in the absence of such
        agreement the matter shall be referred to an Expert for determination.

9.9     ATTENDANCE AT TEST: The Seller shall give KPLC reasonable notice of its
        intention to conduct a Contracted Early Generation Capacity Test or
        Contracted Plant Capacity Test (as the case may be) and KPLC shall be
        entitled to attend or send representatives to witness such test.

9.10    ADDITIONAL TESTS: In addition to the tests provided for in Clauses 9.8
        and 9.8A, and subject to the provision of reasonable advance notice, the
        Seller may at any time and from time to time conduct a further test and
        the provisions of Clauses 9.8, 9.8A and 9.9 shall apply thereto, mutatis
        mutandis. KPLC shall have the right to call for a Contracted Early
        Generation Capacity Test or a Contracted Plant Capacity Test (as the
        case may be) in the case of an Availability Failure which continues for
        eight (8) consecutive Settlement Periods. Without prejudice to such
        right, KPLC may call for a test no more frequently than one hundred
        eighty (180) days from the previous test, and the provisions of Clauses
        9.8, 9.8A and 9.9 shall apply thereto, mutatis mutandis.



                                       28





        Notwithstanding the provisions of Clauses 9.8, 9.8A, 9.9 and 9.10, the
        Seller may, in its sole discretion, repeat, as soon as practicable and
        in any event within six (6) hours any test when such test was
        unsuccessful due to mechanical or electrical failure of the equipment
        provided that the Seller gives notice to KPLC of the repetition of a
        Contracted Early Generation Test or Contracted Plant Capacity Test (as
        the case may be) before or within fifteen (15) minutes of the conclusion
        of the previous test.

9.11    AVAILABILITY FAILURE: If, within twenty-four (24) hours of an
        Availability Failure which continues for eight (8) consecutive
        Settlement Periods, KPLC calls for a Contracted Early Generation
        Capacity Test or Contracted Plant Capacity Test (as the case may be)
        pursuant to Clause 9.10 and such test demonstrates that the capacity
        available is less than the Contracted Early Generation Capacity Test or
        Contracted Plant Capacity (as the case may be) then for the period
        beginning from the Settlement Period within which such Availability
        Failure occurred and ending when the Available capacity has been agreed
        or determined pursuant to the Contracted Early Generation Test or
        Contracted Plant Capacity Test (as the case may be), the Contracted
        Early Generation Capacity or Contracted Plant Capacity for such period
        shall be equal to the average Availability of the Early Generation
        Facility or the Plant (as the case may be) achieved in response to
        Despatch Instructions for the Settlement Periods in which such
        Availability Failure occurred or the capacity demonstrated to be
        Available by such test, if greater.

9.12    RESTORATION OF CAPACITY: Notwithstanding the provisions of Clauses 9.8,
        9.8A, if in any period of three (3) months the average Contracted Early
        Generation Capacity or Contracted Plant Capacity, demonstrated by tests
        conducted over that period, is less than sixty per cent (60%) of the
        Contracted Early Generation Capacity at the Signature Date or Contracted
        Plant Capacity agreed or determined in accordance with Clause 5 (as the
        case may be), and provided that the Reservoir can sustain the required
        steam flow, the Parties shall forthwith meet and agree a programme to be
        implemented by the Seller during the next following six (6) month period
        for restoring the Contracted Early Generation Capacity or Contracted
        Plant Capacity (as the case may be) to ninety-eight per cent (98%) (in
        the five (5) years immediately following the Early Generation Commercial
        Operation Date or the Full Commercial Operation Date (as the case may
        be)) or otherwise to ninety-five per cent (95%) of the level at which it
        was on the Signature Date or agreed or determined in accordance with
        Clause 5 (as the case may be). If the Seller fails to so restore the
        Contracted Early Generation Capacity or Contracted Plant Capacity during
        the said six (6) month period, the Capacity Payments from the end of
        such six (6) month period until the date on which the capacity is
        restored in accordance with Clause 9.12 shall be multiplied by a factor
        of decimal five (0.5), the Parties hereby agreeing that such adjustment
        represents a genuine pre-estimate of the cost to KPLC for procuring
        alternative generating capacity which the Seller is unable to provide.

9.13    DISPUTES: Any dispute as to the results of a Contracted Early Generation
        Capacity Test or Contracted Plant Capacity Test (as the case may be)
        shall be referred to an Expert.



                                       29





CLAUSE 10: SALE AND PURCHASE OF ELECTRICITY

10.1    SALE AND PURCHASE I: From the Early Generation Commercial Operation Date
        the Seller shall sell and KPLC shall purchase all the Net Electrical
        Output of the Early Generation Facility generated in accordance with
        Despatch Instructions.

10.1A   SALE AND PURCHASE II: From the Full Commercial Operation Date the Seller
        shall sell and KPLC shall purchase all the Net Electrical Output of the
        Plant supplied in accordance with Despatch Instructions.

10.2    ENERGY CHARGES: KPLC shall pay the Seller Energy Charges ascertained in
        accordance with Parts A and B of Schedule 5 in respect of all Net
        Electrical Output sold and purchased in accordance with Clauses 10.1 and
        10.1A respectively.

10.3    DELIVERY POINT: Electricity sold and purchased under this Agreement
        shall be delivered at the Delivery Point and all transmission losses
        before the Delivery Point shall be for the Seller's account and all
        transmission losses beyond the Delivery Point shall be for KPLC's
        account.

10.4    METERED QUANTITIES: The quantities of Net Electrical Output delivered at
        the Delivery Point shall be metered and determined in accordance with
        the provisions of Clause 12.

10.5    CAPACITY PAYMENTS: KPLC shall in respect of the month in which the Early
        Generation Commercial Operation Date occurs and for each month
        thereafter during the Term pay the Seller for the Contracted Early
        Generation Capacity, and KPLC shall in respect of the month in which the
        Full Commercial Operation Date occurs and for each month thereafter
        during the Term pay the Seller for the Contracted Plant Capacity (each,
        as the case may be, with adjustments reflecting Availability), in
        accordance with Part A or B of Schedule 5.

10.6    FURTHER PROVISIONS: The further provisions of Parts A and B of Schedule
        5 shall take effect for the purposes of determining the amounts from
        time to time payable by KPLC by way of Energy Charges and Capacity
        Payments.

10.7    DESPATCH: KPLC intends to despatch the Early Generation Facility or the
        Plant (as the case may be) if it is declared Available provided that it
        shall have no liability under this Agreement (other than its obligations
        to make Capacity Payments) or otherwise if it fails to do so; including
        in relation to any Plant Annual Target Output Bonuses foregone by the
        Seller as a result.

10.8    TAXES AND DUTIES: If at any time after the Signature Date, there is a
        change in the rate of Taxes and Duties which gives rise to an increase
        or decrease in the level of costs incurred by the Seller in the design,
        construction or operation of the Early Generation Facility or the Plant
        or the conduct of the Appraisal Works either Party may within 3 months
        of the change occurring by notice to the other seek an adjustment to the
        Energy Charges and/or Capacity Payments which will have the effect of
        placing the Seller in the same financial position as it would have been
        in had the change not occurred. The Parties shall meet and endeavour to
        agree to the adjustment and if the Parties shall fail within thirty (30)
        days of a notice under this



                                       30



        Clause 10.8 to agree upon such adjustment either Party may refer the
        matter to an Expert who shall be an internationally recognised public
        accounting firm and who shall be free to accept proposals for such
        adjustments or make such directions as to the appropriate adjustment as
        he shall deem fit.



CLAUSE 11: INVOICING AND PAYMENT

11.1    INVOICE I: The Seller shall with respect to the Early Generation
        Facility, within thirty (30) days of the end of each month (beginning
        with the month in which the Early Generation Commercial Operation Date
        occurs until the Early Generation Cessation Date (if any)) prepare and
        issue to KPLC an invoice in respect of the payments due from KPLC for
        that month.

11.1A   INVOICE II: The Seller shall with respect to the Plant, within thirty
        (30) days of the end of each month (beginning with the month in which
        the Plant Commissioning Date occurs until the expiry of the Term)
        prepare and issue to KPLC an invoice in respect of the payments due from
        KPLC for that month.

11.2    CONTENT OF INVOICE: Each invoice prepared by the Seller shall be
        substantially in the form set out in Part C of Schedule 5 and shall
        contain the information specified in that Part determined on the basis
        of relevant quantities metered and recorded in accordance with Clause
        12. KPLC shall be entitled, no later than five (5) days after receipt,
        to reject any invoice which does not materially conform to Part C of
        Schedule 5 or which is not accompanied by all the supporting
        documentation agreed by the Parties provided that no later than four (4)
        days after receipt of such invoice, KPLC shall notify the Seller of the
        information which it requires in accordance with Part C of Schedule 5,
        in order to process the invoice and the Seller shall have the right to
        furnish such information or documentation as KPLC may reasonably
        require. If KPLC so rejects an invoice the Seller shall be deemed not to
        have issued or delivered an invoice to KPLC and KPLC shall not be
        required to make any payments to the Seller. In such event, the
        provisions of this Clause 11.2 shall be repeated until such time as the
        Seller issues an invoice which conforms to Part C of Schedule 5 and
        which is accompanied by all the supporting documentation agreed by the
        Parties.

11.3    PAYMENT DUE DATE: Energy Charges, Capacity Payments and any other
        amounts payable by KPLC hereunder shall be due and payable within thirty
        (30) days after the date of delivery of the invoice.

11.4    LATE PAYMENT INTEREST: Any amount properly due from KPLC to the Seller
        under this Agreement and remaining unpaid after the due date for payment
        shall bear interest at the Default Rate from and including the date when
        the amount in question was due until but excluding the date when it is
        received by the Seller, accruing from day to day and compounded
        quarterly.

11.5    DISPUTED PAYMENTS: If any sum or part of any sum shown on an invoice
        rendered by the Seller is disputed in good faith by KPLC then the
        payment of the undisputed sums or parts shall not be withheld on those
        grounds and shall be paid to the Seller when due; and interest at the
        Non-Default Rate shall be payable on any disputed sum subsequently
        agreed or judged to be due from and including the date when the sum in
        question was due until but excluding the date when it is received by the
        Seller,



                                       31





        accruing from day to day and compounded quarterly. Any disputed payment
        will be resolved in accordance with the Good Faith Dispute Procedure.

11.6    TAXES, ETC: Except as otherwise provided, all payments under this
        agreement shall be made free and clear from, and without set-off,
        deduction or withholding on account of, any form of Taxes and Duties,
        save to the extent that KPLC is duly appointed by the Commissioner for
        Income Tax as agent for the Seller under section 96 of the Income Tax
        Act and makes payments to the Commissioner of Income Tax as agent for
        the Seller pursuant to sub-section 96(3) as the same may be re-enacted,
        amended, replaced or modified.

11.7    THE SELLER'S ACCOUNT: Payment of any sum payable under this Clause shall
        be effected through wire transfer to the account of the Seller at a bank
        located outside the Republic of Kenya or such other bank as may be
        notified by the Seller to KPLC from time to time provided that such
        payment shall be made on a business day and shall be net of all bank
        charges payable by KPLC in connection with such transfer.

11.8    CURRENCY FOR PAYMENTS: Unless otherwise agreed by the Parties in
        writing, all amounts falling due under this Agreement shall be payable
        in United States Dollars and the Seller shall not be obliged to accept
        payment in any other currency.

11.9.1  SECURITY: As security for the payment of sums payable by KPLC under
        Clause 11 of this Agreement, the Parties have entered into the Olkaria
        III Project Security Agreement, pursuant to which KPLC will provide a
        letter of Credit. OrPower 4 will meet certain expenses with respect to
        the Letter of Credit, all as provided under the Olkaria III Project
        Security Agreement. If any such expenses which OrPower 4 is liable to
        reimburse are due and owing despite KPLC's written demand to the Seller
        for payment of such amounts, KPLC may offset such amounts against
        payments owing by KPLC under Clause 11 hereto.

11.9.2  DEEMED PAYMENT: No later than thirty (30) days after the date on which
        the Seller becomes entitled to make a demand under the Letter of Credit,
        the Seller shall take all steps necessary to make such a demand in
        writing of all moneys due and owing to the Seller (and not dispute by
        KPLC) under the Letter of Credit. If and to the extent that moneys are
        paid to the Seller under the Letter of Credit, the undisputed amounts
        due under an invoice which has not been paid in accordance with Clause
        11.3 shall be deemed to that extent to have been paid by KPLC to the
        Seller on the date of actual payment and on and with effect from such
        date he provisions of Clauses 11.4 and 16.2(c) shall cease to apply in
        relation to the sums so paid.

11.9.3  FAILURE TO DEMAND: If the Seller fails to take all steps necessary to
        demand moneys in writing under the Letter of Credit within the
        aforementioned thirty (30) days and to the extent that moneys are
        available to the Seller under the Letter of Credit, the provisions of
        Clauses 11.4 and 16.2(c) shall not apply following the thirtieth (30th)
        day after an invoice becomes due.




CLAUSE 12: METERING

12.1    METERING PARTY'S OBLIGATIONS: Each Party (the "Metering Party") shall
        not later than the Early Generation Commissioning Date install (or
        procure the installation of) and



                                       32





        shall maintain and operate that part of the Metering System for which it
        is responsible in accordance with Part D of Schedule 2.

12.2    NON-METERING PARTY'S RIGHTS: With respect to all components of the
        Metering System for which the other Party is the Metering Party, each
        Party (the "Non-Metering Party") shall have the right to its own
        expense:

        (a)  to inspect such parts of the Metering System upon reasonable
             notice;

        (b)  to attend and witness tests, adjustments and recalibration of such
             parts of the Metering System carried out by the Metering Party
             pursuant to Part B of Schedule 4; and

        (c)  to request the testing, adjustment for error and recalibration of
             such parts of the Metering System.

12.3    SPECIFICATION, ETC. OF METERING SYSTEM: The specification and required
        limits of accuracy of Metering System, and the metering point (the
        electrical point at which such Metering System is positioned), shall be
        as specified in Part D of Schedule 2, provided that where the metering
        point is not specified it shall be located as near as possible to the
        Delivery Point.

12.4    DEFECTIVE METERING SYSTEM: Where it is agreed or determined that any
        part of the Metering System is defective (including operating outside
        the relevant limit of accuracy in Part D of Schedule 2), then such part
        of the Metering System shall be repaired, adjusted or replaced at the
        cost of the Metering Party.

12.5    METER ERROR: Where in the circumstances referred to in Clause 12.4 it is
        necessary to redetermine any quantity measured or recorded by the
        defective Metering System the provisions of paragraph 2(b) of Part B
        Schedule 4 shall apply.

12.6    METER SEALING: The Metering System shall comply with the specifications
        set out in Part D of Schedule 2 and shall be jointly sealed. Such seals
        shall be broken only by KPLC personnel. The Seller shall be given at
        least twenty-four (24) hours advance notice of the breaking of seals on
        the Metering System provided however that no such notice will be
        necessary when the breaking of a seal is necessitated by the occurrence
        of an Emergency.

12.7    METER TAMPERING: KPLC and the Seller undertake not to tamper or
        otherwise interfere with the Metering System in any way with the object
        of effect of distorting the quantity measured or recorded by the
        Metering System. Where it is established that the Metering System has
        been tempered or interfered with, the quantity measured or recorded
        shall be determined in accordance with paragraph 2(b) or Part B of
        Schedule 4.

12.8    METERING PROCEDURES: The Parties shall adopt and implement the
        procedures and arrangements set out in Part B of Schedule 4 for reading,
        testing, adjusting and recalibrating the Metering System.



                                       33





12.9    DISPUTES: Any dispute arising under this Clause 12, Part D of Schedule 2
        or Part B of Schedule 4 shall be referred to the determination of an
        Expert.

12.10   SATISFACTION OF REQUIREMENTS:

        The Parties hereby acknowledge that as of the date hereof, all of the
        obligations, requirements and arrangements under Clause 12 with
        respect to the Metering System of the Early Generation Facility have
        been satisfied in full.


CLAUSE 13: INSURANCE

        The Seller shall:

        (a)  take out and maintain in full force and effect such policies of
             insurance as are specified in Schedule 9 with reputable insurance
             companies approved by KPLC (such approval not to be unreasonably
             withheld);

        (b)  provide to KPLC copies of all policies effected by it and evidence
             that the premiums payable thereunder have been paid;

        (c)  provide access to KPLC or its representatives to its offices to
             inspect the original policies;

        (d)  subject to the Financing Agreements, apply the proceeds of claims
             against such policies, relating to damage to the Early Generation
             Facility or the Plant (as the case may be) in repairing and
             restoring the Early Generation Facility or the Plant (as the case
             may be) unless the damage is such as to make the Early Generation
             Facility or the Plant a total loss and the Parties deem the Early
             Generation Facility or the Plant to be irreparable; and

        (e)  obtain waivers of rights of subrogation against KPLC.



CLAUSE 14: UNDERTAKINGS AND WARRANTIES OF THE PARTIES

14.1    UNDERTAKINGS OF THE SELLER: The Seller undertakes that:

        (a)  it shall comply with all applicable Legal Requirements; and

        (b)  it shall use all reasonable endeavours to keep in force all
             Authorisations required to be in the Seller's name for the
             operation of the Early Generation Facility and the Plant and any
             other of its obligations under this Agreement and that it will
             indemnify KPLC against all costs incurred by KPLC in the discharge
             of its obligations under Clause 14.3(c) below in accordance with
             any specific Seller requests;

        (c)  the Early Generation Facility and the Plant shall be constructed,
             maintained and operated in accordance with the terms of this
             Agreement;

        (d)  it shall issue such number of fully paid shared or other securities
             constituting shareholders funds on its balance sheet as shall in
             aggregate at the Early Generation Commercial Operation Date and at
             the Full Commercial Operation



                                       34





             Date amount to not less than twenty-five per cent (25%) of the
             total investment made by the Seller for the purposes of this
             Agreement as at such date and for the purposes of this Clause
             14.1(d), "total investment" shall in respect of the Early
             Generation Facility mean a sum equal to seventeen million five
             hundred thousand US Dollars (US$17,500,000) and in respect of the
             Plant, "total investment" shall mean a sum that shall amount to
             not less than one hundred and thirty-three per cent (133%) of the
             aggregate sum borrowed by the Seller pursuant to the Financing
             Agreements; and

        (e)  it will use commercially reasonable efforts to carry out its
             respective obligations for the Establishment Date by the Target
             Establishment Date and to diligently pursue necessary approvals in
             a timely fashion.

14.2    REPRESENTATIONS AND WARRANTIES OF THE SELLER: The Seller represents and
        warrants that:

        (a)  the Seller is a limited liability company duly organised and
             validly existing under the laws of the Cayman Islands and has all
             requisite legal power and authority to execute this Agreement and
             to carry out the terms, conditions and provisions hereof;

        (b)  this Agreement constitutes the valid, legal and binding obligation
             of the Seller, enforceable in accordance with the terms hereof
             except as the enforceability may be limited by applicable laws
             affecting creditors' rights generally;

        (c)  there are no actions, suits or proceedings pending or, to the
             Seller's knowledge, threatened, against or affecting the Seller
             before any court or administrative body or arbitral tribunal that
             might materially adversely affect the ability of the Seller to meet
             and carry out its obligations under this Agreement;

        (d)  the execution, delivery and performance by the Seller of this
             Agreement have been duly authorised by all requisite corporate
             action, and will not contravene any provision of, or constitute a
             default under, any other agreement or instrument to which it is a
             party or by which it or its property may be bound.

14.3    UNDERTAKINGS OF KPLC: KPLC undertakes that it shall:

        (a)  comply with all applicable Legal Requirements and will keep in
             force all Authorisations required for the performance of its
             obligations under this Agreement;

        (b)  assist the Seller in obtaining on a timely basis (as required under
             Clause 3, and the Construction Programme) and to assist the Seller
             in maintaining until the first anniversary of the Full Commercial
             Operation Date (to the extent that KPLC can so do) all
             Authorisations required by the Seller;

        (c)  to the extent there is a Change in Law, use reasonable endeavours
             to assist the Seller to obtain all Authorisations necessary for the
             continued operation or



                                       35





             maintenance of the Plant or for the Geothermal Reservoir
             Development in accordance with any specific Seller requests; and

        (d)  it will use commercially reasonable efforts to carry out its
             respective obligations for the Establishment Date by the Target
             Establishment Date and to diligently pursue necessary approvals in
             a timely fashion.

14.4    REPRESENTATIONS AND WARRANTIES OF KPLC: KPLC represents and warrants
        that:

        (a)  KPLC is a limited liability company duly organised and validly
             existing under the laws of Kenya and has all requisite legal power
             and authority to execute this Agreement and to carry out the terms,
             conditions and provisions hereof;

        (b)  all legislative, administrative or other governmental action
             required to authorise the execution, delivery and performance by
             KPLC of this Agreement and the transactions contemplated hereby
             have been taken and are in full force and effect;

        (c)  this Agreement constitutes the valid, legal and binding obligation
             of KPLC, enforceable in accordance with the terms hereof except as
             the enforceability may be limited by applicable laws affecting
             creditors' rights generally;

        (d)  there are no actions, suits or proceedings pending or, to KPLC's
             knowledge, threatened, against or affecting KPLC before any court
             or administrative body or arbitral tribunal which might materially
             adversely affect the ability of KPLC to meet and carry out its
             obligations under this Agreement; and

        (e)  the execution, delivery and performance by KPLC of this Agreement
             have been duly authorised by all requisite corporate action, and
             will not contravene any provision of, or constitute a default
             under, any other agreement or instrument to which it is a party or
             by which it or its proper may be bound.




CLAUSE 15:  FORCE MAJEURE

15.1    EVENTS OF FORCE MAJEURE: For the purposes of this Agreement "Force
        Majeure" means, subject to Clause 15.2, any event or circumstance which
        affects either Party and is not within the reasonable control (directly
        or indirectly) of the Party affected, to the extent that such event or
        circumstance or its effects cannot be prevented, avoided or removed by
        such Party acting in accordance with Prudent Operating Practice. "Force
        Majeure" shall (save as is provided in Paragraph 6 of Part A of Schedule
        5 and Paragraph 8 of Part B of Schedule 5) include each of the following
        events and circumstances to the extent that they satisfy the foregoing
        requirements:

        (i)   any act of war (whether declared or undeclared), invasion, armed
              conflict or act of foreign enemy, blockade, embargo, revolution,
              riot, insurrection, civil commotion, act of terrorism, or sabotage
              provided that any such event occurs within or directly involves
              the Republic of Kenya or any other country from which machinery,
              equipment and materials for the Early Generation Facility or the
              Plant are procured or transported through;



                                       36



        (ii)  an act of God including but not limited to lightning, fire,
              earthquakes, volcanic activity, floods, storms, cyclones,
              typhoons, or tornadoes;

        (iii) epidemics or plagues;

        (iv)  explosions or chemical contamination (other than resulting from an
              act of war);

        (v)   labour disputes including strikes, works to rule or go-slows or


              lockouts that extend beyond the Plant or are widespread or
              nationwide;

        (vi)  Change in Law.

15.2    EXCLUSIONS FROM FORCE MAJEURE: The following events or circumstances
        shall not constitute Force Majeure:

        (a)  late delivery to the Seller of machinery, equipment, materials,
             spare parts or consumables save where such late delivery is itself
             due to Force Majeure;

        (b)  a delay in the performance of any contractor save where such delay
             is itself due to Force Majeure;

        (c)  breakdowns in equipment save where such breakdown is itself due to
             Force Majeure;

        (d)  normal wear and tear or random flaws in materials and equipment;

        (e)  payment of monies due provided that relief under this Clause 15
             shall extend to failure caused by circumstances or events of Force
             Majeure affecting all reasonable means of payment;

        (f)  any failure to perform obligations under this Agreement to the
             extent that such failure results from or is caused by insufficient
             Steam Field Facilities or by adverse Reservoir conditions,
             including insufficiency of reserves, prevailing within the
             Geothermal Reservoir (including insufficient capacity in the
             Seller's Steam Field Facilities);

        (g)  a Change in Law in the circumstances described in Clause 10.8.

15.3    EFFECT OF FORCE MAJEURE: If a Party is prevented from or delayed in
        performing an obligation hereunder by reason of Force Majeure the
        affected Party shall:

        (a)  be relieved from the consequences of its failure to perform that
             obligation;

        (b)  promptly notify the other Party of the occurrence of the event; and

        (c)  use all reasonable endeavours to overcome the consequences of the
             event.

15.4    CONSTRUCTION FORCE MAJEURE: Where the Seller is as a result of an event
        of Force Majeure (including a failure by KPLC to perform any of its
        obligations under this



                                       37





        Agreement) delayed in or prevented from performing any of its
        obligations before the Long Stop Dates (or any of them) the Long Stop
        Dates which have not then occurred shall be revised to new dates which
        reflect the period of delay resulting from such Force Majeure or failure
        provided that no Long Stop Dates may be delayed by more than one hundred
        and eighty (180) days in aggregate.

15.5    PAYMENTS DURING FORCE MAJEURE: Save where a specific payment remedy is
        available to the Seller under this Agreement, upon the occurrence of any
        Force Majeure event after the Early Generation Commercial Operation
        Date, then during the Force Majeure event or KPLC failure to perform any
        of its obligations under this Agreement, KPLC shall pay to the Seller
        Energy Charges for the Net Electrical Output delivered in accordance
        with Despatch Instructions during such Force Majeure event or failure
        plus a Capacity Payment in accordance with paragraph 8 of Part A of
        Schedule 5.

        Notwithstanding the above, the payments referred to under this Clause
        15.5 shall not be paid during the period of actual construction of the
        Plant prior to the achievement of Full Commercial Operation with respect
        to the anticipated capacity of the Plant, but shall be paid in full with
        respect to the Early Generation Facility.

15.6    FORCE MAJEURE TERMINATION: If an event of Force Majeure continues beyond
        a period of two hundred and seventy (270) days, the Parties shall meet
        in good faith to consult for a further period of not less than ninety
        (90) days to reach a solution acceptable to all Parties. If, at the end
        of such ninety (90) day period, no such solution is found, either Party
        shall be entitled to terminate this Agreement by giving written notice
        of not less than seven (7) days to the other Party.




CLAUSE 16: TERMINATION AND DEFAULT

16.1    THE SELLER'S EVENTS OF DEFAULT: For the purposes of this Agreement an
        Event of Default in respect of the Seller shall be:

        (a)  subject to the provisions of Clause 16.4, any of the following
             events:

             (i)  the wilful and unexcused failure by the Seller to operate the
                  Early Generation Facility or the Plant in compliance with
                  Despatch Instructions and in accordance with the provisions of
                  this Agreement without the written consent of KPLC after the
                  Early Generation Commercial Operation Date or the Full
                  Commercial Operation Date (as the case may be);

             (ii) the breach by the Seller of any of its material obligations
                  under this Agreement. However, the Seller's failure either in
                  the event of Under-Generation under Clause 8.7, Availability
                  Failure under Clause 9.11, or prolonged failure to achieve the
                  required Contracted Capacity under Clause 9.12 shall not
                  constitute a Default in respect of the Seller under this
                  Clause unless and until the period for restoring the
                  Contracted Early Generation Capacity or Contracted Plant
                  Capacity (as the case may be) provided under Clause 9.12 has
                  expired and restoration of the capacity has not been achieved
                  as required therein, and provided



                                       38





                  further that any Seller failure under Clause 14.1(e) shall not
                  constitute a Default in respect of the Seller;

        (b)  in relation to the Seller or its assets, the commencement of
             bankruptcy, insolvency, winding up, liquidation, or other similar
             proceeding, or the appointment of a trustee, liquidator, custodian,
             receiver of similar person, unless such proceeding or appointment
             is capable of being and is set aside or stayed within sixty (60)
             days.

16.2    KPLC DEFAULTS: For the purposes of this Agreement a Default in respect
        of KPLC shall be:

        (a)  subject to the provisions of Clause 16.4, the breach by KPLC of any
             of its material obligations under this Agreement other than the
             failure to make any payments under this Agreement when due and
             payable;

        (b)  in relation to KPLC or its assets, the commencement of bankruptcy,
             insolvency, winding up, liquidation, or other similar proceeding,
             or the appointment of a trustee, liquidator, custodian, receiver or
             similar person, unless such proceeding or appointment is capable of
             being and is set aside or stayed within sixty (60) days; and

        (c)  any failure to pay any sum of money due and owing for 90 days or
             more from the date when such sum was first due and demanded and
             which sum is not subject to a bona fide dispute.

16.3    DEFAULTING PARTY, ETC: For the purposes of this Agreement the Seller is
        the defaulting Party in relation to the Defaults specified in Clause
        16.1 and KPLC is the defaulting Party in relation to the Defaults
        specified in Clause 16.2, and (in each case) the other Party is the
        non-defaulting Party.

16.4    REMEDIAL PROCEDURES: Upon the occurrence of any Default, the
        non-defaulting party may give notice to the defaulting Party of the
        occurrence of such Default and (in the case of a Default capable of
        remedy) requiring the remedy thereof; and if after such notice has been
        given:

        (a)  the defaulting Party does not, within thirty (30) days after
             receipt of the non-defaulting Party's notice:

             (i)  where such Default is capable of remedy within such thirty
                  (30) day period, remedy the default; or

             (ii) where such Default is capable of remedy but not within such
                  thirty (30) day period, furnish to the non-defaulting Party a
                  detailed programme ("Remedial Programme") for the remedy as
                  promptly as is practicable of the Default; or

        (b)  the defaulting Party fails to remedy the Default in accordance with
             the Remedial Programme, or such Default is not capable of remedy,



                                       39





        then the non-defaulting Party may give notice to the defaulting Party
        that such Default is an "Event of Default", but not event specified in
        Clause 16.1(a) or 16.2(a) which is capable of remedy shall be an Event
        of Default except pursuant to the provisions of this Clause 16.4.

16.5    TERMINATION: Upon an Event of Default the non-defaulting Party may upon
        not less than seven (7) days notice to the defaulting Party terminate
        this Agreement.

16.6    SURVIVAL OF RIGHTS: The expiry or termination of this Agreement shall
        not affect any rights or obligations which may have accrued prior to
        such expiry or termination and shall not affect obligations of each of
        the Parties under this Agreement which are expressed to continue after
        such expiry or termination.

16.7    TERMINATION DUE TO NON-SATISFACTION OF CONDITIONS PRECEDENT:
        Notwithstanding any provision contained herein to the contrary, if this
        Agreement is terminated in circumstances where any of the conditions
        referred to in Part A of Schedule 6 has not been satisfied by the Long
        Stop Effective Date other than by reason of a breach by the Seller of
        its obligations under Clause 3.2, KPLC shall pay the Seller for its
        costs and expenses incurred with respect to this Agreement, a lump sum
        amount of one million United States Dollars (US$1,000,000) within thirty
        (30) days of such termination.

16.8    SATISFACTION OF REQUIREMENTS:

        The Parties hereby acknowledge that all of the Conditions Precedent have
        been fulfilled.




CLAUSE 17: INDEMNIFICATION AND LIABILITY

17.1    LIABILITY: Subject to Clauses 17.2, 17.3 and 17.4, each Party shall be
        liable to the other Party for the loss directly and foreseeably
        resulting from any breach by the first Party of its obligations
        hereunder.

17.2    OWN LOSS: Notwithstanding Clause 17.1, each Party shall be responsible
        for, and shall indemnify the other Party against claims in respect of,
        loss of or damage to persons or property incurred by the first Party and
        its contractors, employees and agents resulting from the act, omission
        or negligence of either Party in performance of or otherwise in
        connection with this Agreement.

17.3    EXCLUDED LIABILITY: Except as provided in Clause 17.1, neither Party
        shall have any liability to the other for any loss or damage or other
        liability, whether arising in contract, tort or otherwise, in connection
        with this Agreement.

17.4    CONSEQUENTIAL LOSSES: In no case shall either Party be liable to the
        other for any indirect or consequential losses or damages.




CLAUSE 18: CONFIDENTIALITY

18.1    CONFIDENTIAL INFORMATION: Each Party agrees that it will, and will
        ensure that its employees, officers and directors will, hold in
        confidence all information, documentation, data and know-how disclosed
        to it by the other Party and designated in writing as 'confidential'
        ("Confidential Information"), and will not disclose to any



                                       40





        third party or use Confidential Information or any part thereof without
        the other Party's prior written approval, provided that:

        (a)  this Clause shall not apply to Confidential Information which is in
             the public domain other than by reason of a breach of this Clause
             18.1, or was already in the rightful possession of the recipient
             Party, or was obtained by the recipient Party in good faith from a
             third party entitled to disclose it; and

        (b)  a Party may disclose Confidential Information in accordance with
             any legal requirement to do so, or to financial institutions,
             multi-lateral agencies, consultants and contractors whose duties
             reasonably require such disclosure.

18.2    SURVIVAL: The provisions of this Clause 18 shall survive the termination
        or expiry of this Agreement.


CLAUSE 19: DISPUTE RESOLUTION

19.1    GOOD FAITH DISPUTE RESOLUTION PROCEDURE

If either Party raises a dispute in good faith under or in connection with this
Agreement or with the Olkaria III Project Security Agreement, it shall be
resolved according to the following procedure ("Good Faith Dispute Resolution
Procedure"):

For 15 calendar days after receipt of notice of dispute, the Parties shall
exercise their best efforts to resolve the dispute. If no resolution is achieved
within such 15 day period, within two business days of the end of the 15 day
period, the disputing Party has notified the other Party of its intention to
contest and refer the dispute to arbitration or to an agreed Expert in
accordance with the relevant terms of the Agreement or the Olkaria III Project
Security Agreement (as the case may be), and, within twenty-eight (28) days from
the end of the above 15 day period, refers the dispute to and diligently pursues
contestation of the dispute in arbitration proceedings or before an agreed
Expert in accordance with the relevant terms of the Agreement or the Olkaria III
Project Security Agreement (as the case may be).



19.2    ARBITRATION: Subject to Clauses 19.1 and 19.3 any dispute or difference
        of any kind between the Parties in connection with or arising out of
        this Agreement or the breach, termination or validity hereof (a
        "Dispute") shall be finally settled under the Rules of Conciliation and
        Arbitration of the International Chamber of Commerce in accordance with
        the said Rules which Rules are deemed to be incorporated by reference
        into this Clause 19.2. It is hereby agreed that:

        (a)  The site of the arbitration shall be London, England;

        (b)  There shall be a single arbitrator;

        (c)  The language of the arbitration shall be English;

        (d)  The award rendered shall apportion the costs of the arbitration;

        (e)  The award shall be in writing and shall set forth in reasonable
             detail the facts of the Dispute and the reasons for the tribunal's
             decision;



                                       41





        (f)  The award in such arbitration shall be final and binding upon the
             Parties and judgement thereon may be entered in any Court having
             jurisdiction for its enforcement; and the Parties renounce any
             right of appeal from the decision of the tribunal insofar as such
             renunciation can validly be made.

        If there is a conflict between this Agreement and the said Rules, this
        Agreement shall prevail.

19.3    EXPERT: Where the Agreement provides that any Dispute or other matter
        shall be referred to an Expert or the Parties so agree:

        (a)  The Expert shall be an independent person who is not of the same
             nationality as either of the Parties with relevant experience and
             willing to act agreed between the Parties or if not agreed within
             fourteen (14) days of a request in writing by either Party
             appointed by the President of the Geothermal Resource Council, P.O.
             Box 1350, Davis, California, CA 95617-1350 or by The Chairman of
             the International Geothermal Association c/o Samorka,
             Sudurlandsbraut 48, Reykjavik, Iceland;

        (b)  For a period of forty-two (42) days after the appointment of the
             Expert of such other period as the Parties may agree, each Party
             may make such written submissions at it wishes to the Expert and
             shall simultaneously provide a copy to the other Party and at the
             end of such forty-two (42) day period each Party shall have a
             period of twenty-one (21) days to make counter-submissions to the
             Expert (with a coy to the other Party) in reply to the other
             Party's written submissions made during the aforementioned
             forty-two (42) day period provided that neither Party shall during
             such twenty-one (21) day period make any written counter-submission

             which purports to reply to raise or refer to any new matters not
             raised or referred to in any submission made during the
             aforementioned forty-two (42) day period;

        (c)  At the end of the twenty-one (21) day period referred to in
             paragraph (b) above and no later than twenty-one (21) days
             thereafter, either Party may, with the consent of the Expert and at
             a time and place decided by the Expert, make an oral presentation
             to the Expert in the presence of the other Party commenting on or
             explaining matters previously submitted to the Expert in writing;

        (d)  The Expert shall render his determination in writing within
             fourteen (14) days of the completion of the oral presentation given
             in accordance with Clause 19.3(c) and give reasonable details of
             the reasons for his determination;

        (e)  The decision of the Expert shall be final and binding on the
             Parties save in the event of fraud or manifest error;

        (f)  The Expert shall act as an expert and not as an arbitrator;

        (g)  In the case of invoices disputed by KPLC in accordance with Clause
             11.5 above, the periods stated in Clause 19.3(b) and (c) above
             shall be reduced


                                       42





             respectively to ten (10) Business Days instead of forty-two (42)
             days and five (5) Business Days instead of twenty-one (21) days.

19.4    EXCLUSIVITY: Neither Party shall have any right to commence or maintain
        any legal proceeding concerning a Dispute relating to this agreement
        until the Dispute has been resolved in accordance with Clauses 19.1
        through 19.3, and then only to enforce or execute the award under such
        procedure.

19.5    CONFIDENTIALITY: The Parties shall each secure that all Experts and
        Arbitrators shall agree to be bound by the provisions of Clause 18 of
        this Agreement as a condition of appointment.

19.6    CONTINUANCE OF OBLIGATIONS: KPLC shall continue to perform its
        obligations under this Agreement during any Expert or arbitration
        proceeding and, provided that all undisputed sums invoiced by the Seller
        have been and continue to be paid, the Seller shall continue to perform
        its obligations under this Agreement during any Expert or arbitration
        proceeding provided that the right to terminate the Agreement pursuant
        to Clause 16 is not restricted by this Clause 19.6.


CLAUSE 20: MAINTENANCE AND OPERATING RECORDS

(a)     Each party shall keep complete and accurate records and all other data
        required by each of them for the purposes of proper administration of
        this Agreement. Among other records and data required hereby or
        elsewhere in this Agreement, the Seller shall maintain an accurate and
        up-to-date operating log, in a format reasonably acceptable to KPLC,
        records of:

        (i)   real and reactive power production for each clock hour and 220 kV,
              33 kV bus voltage (as the case may be) at all times;

        (ii)  changes in operating status, scheduled outages, forced outages and
              partial forced outages;

        (iii) any unusual conditions found during inspections; and

        all such records and data shall be maintained for a minimum of sixty
        (60) months after the creation of such records or data provided that
        each Party shall not dispose of or destroy any such records or data
        after such sixty (60) month period unless the Party desiring to dispose
        of or destroy any such records or data give thirty (30) days prior
        written notice to the other Party, generally describing the records or
        data to be destroyed or disposed of, and the Party receiving such notice
        does not object thereto in writing within ten (10) days. If a written
        objection is received within such ten (10) day period, the objecting
        Party shall have a period of sixty (60) days after the date of such
        written objection within which to inspect and copy the records or data
        proposed to be disposed of or destroyed, which records and data shall be
        made available within such sixty (60) day period by KPLC or the Seller
        as the case may be, at such Party's offices in Nairobi. After the
        expiration of such sixty (60) day period, the Party desiring to dispose
        of or destroy such records or data shall be permitted to do so.


                                       43



(b)     Either Party shall have the right, upon ten (10) days prior written
        notice to the other Party, to examine the records and data of the other
        Party relating to this Agreement or the operation and despatch of the
        Early Generation Facility and the Plant at any time during normal office
        hours during the period such records and data are required hereunder to
        be maintained.



CLAUSE 21: MISCELLANEOUS PROVISIONS

21.1    PROJECT AGREEMENTS AND FINANCING AGREEMENTS:

        (a)  Prior to the execution of this Agreement the Seller has provided to
             KPLC a copy of the articles of association of the Seller, which
             copy has been initialled by the Seller for the purposes of
             identification.

        (b)  As soon as possible after the Signature Date and prior to the award
             of the Turnkey Construction Agreements and the Operating and
             Maintenance Agreement and prior to the signature of the Financing
             Agreements and any Site Agreement the Seller provide to KPLC with
             draft copies of each such contract. The Seller shall have the right
             to delete numerical information and formulae from such draft
             contracts. The Seller shall not enter into any Project Agreement or
             Financing Agreement unless KPLC has been provided with draft copies
             and KPLC has had an opportunity to comment on the draft contracts
             to the Seller.

        (c)  Within fourteen (14) days of receipt of the draft contracts, KPLC
             shall have the right to provide comments to the Seller on the draft
             contracts if KPLC is of the reasonable opinion that:

             (i)  the terms of such Project Agreement or Financing Agreement
                  shall be incompatible with or conflict with the provisions of
                  this Agreement or materially impair the performance or
                  implementation of this Agreement; or

             (ii) any costs which are passed through to or borne by KPLC under
                  the terms of this Agreement are or may reasonably be expected
                  to be increased.

             On receipt of KPLC's comments, the Seller shall try to remove the
             concerns of KPLC.

        (d)  Forthwith upon execution of any of the documents referred to in
             Clause 21.1(b) the Seller shall provide to KPLC a copy thereof
             initialled by the Seller for the purposes of identification.

        (e)  If at any time any Project Agreement or Financing Agreement is
             terminated, an amendment or variation is made to any Project
             Agreement or Financing Agreement then the Seller shall deliver to
             KPLC a conformed copy of each such document or (so far as such
             complete document is not in writing) a true and complete record
             thereof within twenty-one (21) days of the date of its execution or
             creation, certified as a true copy by an officer of the Seller.



                                       44





        (f)  Any comments or lack thereof by KPLC shall be without any liability
             whatsoever on the part of KPLC and shall not lessen, diminish or
             affect in any way the obligations of the Seller under this
             Agreement.

21.2    ASSIGNMENT:

21.2.2  Without prejudice to any of KPLC's rights under Clause 21.1, any
        assignment by a Party of all (but not part only) of its rights and
        obligations under this Agreement is permitted but only with the prior
        written consent of the other Party, provided that:

        (a)  such consent shall not be unreasonably withheld or delayed if the
             Party wishing to assign can satisfy the other Party of such
             proposed assignee's financial, technical and legal status and
             ability to observe and perform this Agreement; and

        (b)  the Party wishing to assign shall be given notice to that effect to
             the other Party and such notice shall have given sufficient
             information to show the status and ability of the proposed assignee
             to carry out the terms of this Agreement.

21.2.2  The provisions of Clause 21.2.1 do not apply to the collateral
        assignment by way of security of the Seller's right, title and interest
        in, to and under the PPA and the Olkaria III Project Security Agreement,
        including all of the Seller's rights to payments thereunder. Pursuant to
        Seller's outstanding request, KPLC will negotiate in good faith and, on
        reaching agreement of terms acceptable to all parties, enter into direct
        agreements for, inter alia, the above described collateral assignments
        by way of security with the Seller and its lenders, the execution of
        direct agreements being a prerequisite for achievement of construction
        and term financing of the Plant by a third party investor or lender who
        is not affiliated with the Seller.

21.2.3  No assignment pursuant to Clause 21.2.1 shall be effective unless and
        until the assigning Party has:

        (a)  procured the proposed assignee to covenant directly with the other
             Party (in a form reasonably satisfactory to such Party) to observe
             and perform all the terms and conditions of this Agreement and if
             reasonably required by the other Party arrange for a guarantee or
             other equivalent security in favour of such other Party in respect
             of all obligations or liabilities to be assigned; and

        (b)  provided to the other Party a certified copy of the assignment
             (excluding the consideration paid or payable for such assignment).

21.3    SUB-CONTRACTORS: The Seller shall be entitled to engage third parties as
        contractors for the performance of its obligations hereunder provided
        that no such engagement shall relieve the Seller of its obligations
        under this Agreement.

21.4    VARIATION: This Agreement may not be varied nor any of its provisions
        waived except by an agreement in writing signed by the Parties.



                                       45





21.5    WAIVERS OF RIGHTS: No delay or forbearance by either Party in exercising
        any right, power, privilege or remedy under this Agreement shall operate
        to impair or be construed as a waiver of such right, power, privilege or
        remedy.

21.6    NOTICES: Except for communications in accordance with the Operating and
        Despatch Procedures, any notice of other communication to be given by
        one Party to the other under or in connection with this Agreement shall
        be given in writing and may be delivered or sent by prepaid airmail or
        facsimile to the recipient at the address, and marked for the attention
        of the person, specified in Schedule 8 or such other address or person
        from time to time designated by notice to the other in accordance with
        this Clause; and any such notice or communication shall be deemed to be
        received upon delivery, or five (5) days after posting, or on
        confirmation of transmission when sent by facsimile.

21.7    EFFECT OF ILLEGALITY, ETC: If for any reason whatever any provision of
        this Agreement is or becomes or is declared by any court of competent
        jurisdiction to be invalid, illegal or unenforceable, then in any such
        case the Parties will negotiate in good faith with a view to agreeing
        one or more provisions to be substituted therefore which are not
        invalid, illegal or unenforceable and produce as nearly as is
        practicable in all the circumstances the appropriate balance of the
        commercial interests of the Parties.

21.8    ENTIRE AGREEMENT: This Agreement contains or expressly refers to the
        entire agreement between the Parties with respect to its subject matter
        and expressly excludes any warranty, condition or other undertaking
        implied at law or by custom and supersedes all previous agreements and
        understandings between the Parties with respect to its subject matter
        and each of the Parties acknowledges and confirms that it does not enter
        into this Agreement in reliance on any representation, warranty or other
        undertaking by the other Party not fully reflected in the terms of this
        Agreement.

21.9    COUNTERPARTS: This Agreement may be executed in two counterparts and by
        each Party on a separate counterpart, each of which when executed and
        delivered shall constitute an original, but both counterparts shall
        together constitute but one and the same instrument.

21.10   WAIVER OF SOVEREIGN IMMUNITY: KPLC agrees that the execution, delivery
        and performance by it of this Agreement and the obligations hereunder,
        constitute private and commercial acts. In furtherance of the foregoing,
        KPLC agrees that:

        (a)  should any proceedings be brought against KPLC or its assets in any
             jurisdiction in connection with this Agreement, or in connection
             with any of KPLC's obligations or any of the transactions
             contemplated by this Agreement, no claim of immunity from such
             proceeding will be claimed by or on behalf of itself or any of its
             assets;

        (b)  it waives any right of immunity which KPLC or any of its assets has
             or may have in the future in any jurisdiction in connection with
             any such proceedings.



                                       46





CLAUSE 22: GOVERNING LAW

22.1    This Agreement shall be governed by and construed in all respects in
        accordance with the laws of Kenya.

AS WITNESS the hands of the duly authorised representatives of the Parties the
day and year first above written.

SIGNED AND SEALED               )
FOR AND ON BEHALF OF            )
THE KENYA POWER &               )
LIGHTING COMPANY LIMITED        )



Director



Secretary


SIGNED for and on behalf of   )
OrPower 4 INC.: BY ERNEST MABWA )  ___________________________

Authorised Representative


                                       47





                              LIST OF ABBREVIATIONS

To promote clarity the following is a listing of the definitions used within
these schedules. Where there is a conflict between this list and a definition
within the schedules then the definition in the schedules shall be used.

A           =   the non escalable component of the Capacity Charge Rate as
                defined in paragraph 1 above (expressed in US$/kW/month);

ACP(tp)     =   the total of the Actual Capacity Payments received in the
                Operating Year for each month up to and including month m;

AC(y)       =   the Available Capacity in Settlement Period y (expressed in kW);

AMA(p)      =   the Actual Monthly Availability of the Plant in month p
                (expressed in kWh);

bara        =   the unit of measurement of pressure with respect to absolute
                zero pressure as defined in the International Standards
                Organisation Standard ISO 1000:1992 Specification for SI Units
                and Recommendations for Use of Their Multiples and Certain Other
                Units;

C           =   the percentage of V represented by the fixed Capacity Charge
                Rate;

CC          =   the Contracted Capacity (expressed in kW);

CCR(p)      =   the Capacity Charge Rate for month p (expressed in US $/kW);

CC(y)       =   the Contracted Capacity (expressed in kW) for Settlement Period
                y;

CPI(b)      =   with respect to the Early Generation Facility, the United States
                Consumer Price Index for June 1996 and, with respect to the
                Plant, the United States Consumer Price Index for March 2005 (=
                193.30) or as otherwise described in Schedule 5 of Part B
                ("Plant Tariff");

CPI(p-I)    =   the United States Consumer Price Index for the month 3 months
                prior to month p;

CP(p)       =   the Capacity Payment for month p (expressed in US $);

E           =   the non escalable component of the Capacity Charge Rate as
                defined in paragraph 1 above (expressed in US$/kW/month);

ECR(b)      =   the Base Energy Charge Rate;

ECR(p)      =   the Energy Charge Rate (expressed in US$/kWh) in month p;

EGAC(y)     =   the Early Generation Available Capacity in Settlement Period y
                (expressed in kW);

EGACP(tp)   =   the total of the Actual Capacity Payments received in the
                Operating Year for each month up to and including month m;

EGCC        =   the Contracted Capacity of the Early Generation Facility
                (expressed in kW);

EGCCR(p)    =   the Capacity Charge Rate for month p (expressed in US$/kW/month)

EGCP(p)     =   the Capacity Payment for month p (expressed in US$);



                                       48





EGD         =   the duration in years between the Early Generation Commercial
                Operation Date and the planned date of the Early Generation
                Cessation Date;

EGEC(p)     =   the aggregate amount of Energy Charges (US$) payable in respect
                of month p;

EGECR(b)    =   the Base Energy Charge Rate;

EGECR(p)    =   the Energy Charge Rate (expressed in US$/kWh) prevailing in
                month p;

EGLC        =   the Capacity on Available as a result of the event of Force
                Majeure (expressed in kW);

EGMTA(P)    =   the Monthly Target Availability (expressed in kWh);

EGNEO(p)    =   the aggregate Net Electrical Output (kWh) of the Early
                Generation Facility in month p;

EGOA        =   Annual Outage Allowance - as described in Schedule 3;

EGSMA(p)    =   the Scheduled Maintenance Allowance in month p (expressed in
                kWh) representing the total energy not available for delivery in
                month p due to scheduled maintenance outages computed assuming
                the Early Generation Capacity would otherwise have been
                dispatched at its Contracted Capacity calculated using the
                values of EGSMA set forth in Schedule 3;

EGUSMA(p)   =   the Unscheduled Maintenance allowance in month p (expressed in
                kWh);

G           =   the percentage of V represented by escalable costs;

H(p)        =   the hours in month p;

H(r)        =   the enthalpy of the geothermal fluid expressed in kJ/kg at each
                well head at the instant that a reading of MF, is taken;

H(y)        =   the number of hours in a year being eight thousand seven hundred
                and sixty (8760);

H(z)        =   the unit of measurement of frequency as defined in the
                International Standards Organisation Standard ISO 1000:1992
                Specification for SI Units and Recommendations for Use of Their
                Multiples and Certain Other Units;

LC          =   the Capacity not Available as a result of the event of Force
                Majeure (expressed in kW);

MEC(p)      =   the aggregate amount of Energy Charges (US$) payable in respect
                of month p;

MF(r)       =   the mass flow rate of geothermal fluid at each well head
                expressed in kg/s;

MTA(p)      =   the Monthly Target Availability (expressed in kWh);

M(y)        =   the number of months in a year being twelve (12);

NEO(p)      =   the aggregate Net Electrical Output (kWh) of the Plant in month
                p;

NEO(T)      =   the Net Electrical Output delivered during the test expressed in
                kWh;

OA          =   the Annual Outage Allowance - as set forth in Schedule 3;



                                       49





PPA(t)      =   the number of years between the Full Commercial Date and end of
                the end of the Term;

SMA(p)      =   the Scheduled Maintenance Allowance in month p (expressed in
                kWh) representing the total energy available for delivery in
                month p due to scheduled maintenance outages computed assuming
                the Plant would otherwise have been dispatched at it Contracted
                Capacity;

SP          =   the number of Settlement Periods in the year;

USMA(p)     =   the Unscheduled Maintenance allowance in month p (expressed in
                kWh); and

V           =   the Base Capacity Charge Rate.



                                       50



                         SCHEDULE 1: APPRAISAL PROGRAMME

                                    See Page _______________


                                       51



          SCHEDULE 2: FACILITIES TO BE INSTALLED BY KPLC AND THE SELLER

                                     PART A

1       FUNCTIONAL SPECIFICATION OF THE PLANT

A.      GENERAL

1.1.    PROJECT DESCRIPTION:

        (a)  INTRODUCTION

             The Seller was required to:

             conduct a detailed Appraisal Programme and to evaluate the existing
             geothermal resources at the Site and to develop wells and the
             geothermal steam field for the supply of steam to the Plant;

             design, build and commission of the Early Generation Facility and
             subsequently, as determined by the appraisal, the Plant;

             connect the Early Generation Facility to the Early Generation
             Interconnection Point; and

             connect the Plant to KPLC's System via a high voltage connection
             leading to the Interconnection Point.

        (b)  GENERAL DESCRIPTION

             As shown in Figure 1, the Olkaria geothermal resource lies about
             five (5) km to the south-east of Lake Naivasha and covers an area
             estimated to be over seventy five (75) square kilometres.

             Except by specific agreement, all of the Early Generation Facility
             and the Plant will be located within the Licence Area indicated on
             the map in Figure 2 in the western area of the resource. KPLC has
             drilled and tested 8 deep wells in the area and these are assigned
             to the Seller for fluid production, reinjection, monitoring and/or
             maintenance.

             The Seller has carried out an appraisal of the geothermal resource
             to establish the capacity of the geothermal resource for power
             generation. An Early Generation Facility of 8 MW Contracted
             Capacity was later increased to approximately 12 MW in the year
             2000, and was constructed at the Site by the Seller as required,
             before the completion of the appraisal of the geothermal resource
             utilising the completed exploration wells for power generation. The
             Early Generation Facility consists of three binary energy
             converters, two of approximately 5 MW gross output each and the
             third of approximately 3 MW output. The converters are air cooled
             and run on the heat energy from geothermal fluid extracted from the
             existing wells drilled by KPLC within the Licence Area. The Early
             Generation Facility supplies electrical energy to


                                       52



             KPLC's System at an agreed voltage through an interconnector
             constructed by KPLC ("KPLC's Transmission Interconnection").

             The Plant will be at a single Site within the geothermal Licence
             Area connected to the wells by pipelines conveying single or dual
             phase steam and water. The Plant will consist of three (3) binary
             energy converter Units of the Early Generation Facility (Units 1, 2
             and 3) and three (3) additional binary energy converter Units
             (Units 4, 5 and 6).

             The Plant will supply electrical energy to KPLC's System through an
             interconnector linking the Plant to a 220 kV substation to be built
             by KPLC at Olkaria II. Following expiry of the Term the Plant shall
             remain fit for further service.

             The Seller shall not drill any wells at any point within 100 metres
             of the boundary of the Licence Area. Drilling may not be directed
             under the area excluded by the licence boundary and the line 100
             metres from the boundary.

             Subject to any legislative or licensing constraints affecting this
             functional specification, the siting of new wells, steam field
             facilities, the Early Generation Facility and the Plant will be the
             responsibility of the Seller who will be expected to conduct its
             operations in accordance with Prudent Operating Practice. GOK will
             make available to the Seller that part of the Site which may be on
             public land. Access to private land will be the responsibility of
             the Seller.

        (c)  SCOPE

             The Seller shall extract geothermal energy from beneath the Licence
             Area in compliance with its geothermal resources licence and
             electric power production license and with this Agreement and shall
             convert the energy efficiently into electricity for sale to KPLC at
             the Early Generation Interconnection Point/Interconnection Point.
             The Early Generation Facility and the Plant shall be designed to
             enable the Seller to meet the obligations of this Agreement.

             The scope of the Seller's duties shall include but not be limited
             to:

             design, procurement, construction, operation and maintenance of the
             existing and additional wells, the steam collection and water
             disposal systems, the Early Generation Facility, the Plant and 220
             kV Transmission Interconnector;

             compliance with the provisions of the geothermal resources licence
             including:

             o    measurement and monthly reporting of the geothermal energy
                  extracted and of the electricity available and supplied; and

             o    monitoring reporting and participating in field management of
                  the geothermal reservoir.


                                       53



1.2     GENERAL INFORMATION:

        (a)  GEOTHERMAL CONSIDERATIONS

             The Seller will follow good geothermal engineering practice in all
             aspects of design drilling and construction operation and
             maintenance particularly including, but not limited to, the effects
             of:

             hot and/or unstable ground;

             elevated temperatures on material properties, equipment
             requirements, well control and other practices;

             hydrogen sulphide and other gases affecting personal safety and
             corrosion of copper-bearing materials;

             earthquakes.

        (b)  AMBIENT CONDITIONS

             The Plant shall be designed and constructed to take account of the
             following ambient conditions:






             (i)     GENERAL

                     Maximum ambient air temperature                   35 DEG.C

                     Minimum ambient air temperature                   1 DEG.C

                     Average ambient air temperature in any one year   18 DEG.C

                     Average relative humidity at midday               57%

                     Minimum relative humidity                         70%

                     Average annual rainfall                           714 mm

                     Isokeraunic level                                 60-70 days/annum

                     Design maximum wind speed                         35 m/s

                     Ambient pressure                                  0.8 bara

             (ii)    REFERENCE CONDITIONS

                     Atmospheric pressure                              0.8 bara

                     Ambient air temperature                           16.5 DEG.C

                     Wet bulb temperature                              13.3 DEG.C




                                       54



1.3     GENERALLY APPLICABLE CODES AND STANDARDS

        The Plant shall comply with the requirements of all applicable
        legislation, orders, decrees, instruments, etc. of the Republic of Kenya
        including but not limited to:

             Health and safety in employment;

             Codes of practice for the design and safety, operation, maintenance
             and servicing of pressure vessels;

             Noise;

             Electricity regulations/codes of practice;

             Public works;

             Fire Protection;

             Environmental Protection

        Where appropriate legislation is not available, the latest version of
        national or international standards will be used to define the minimum
        requirements. The mixing of various national and international standards
        shall only be permitted with the prior approval of KPLC or its
        representative. This Functional Specification is based on the use of one
        set of standards for each discipline:

             Civil Works - Kenyan Standards with supplementary requirements for
             seismic design as given in Unified Building Code of USA;

             Mechanical Works - ASME/ANSI, API and ASHRAE;

             Electrical Control and Instrumentation - IEC, IEEE, ANSI;

             Quality Systems - International Standards Organisation standard ISO
             9000 series;

        Deviations from the referenced standards or substitution by equivalent
        ones shall be subject to the approval of KPLC or its appointed
        representative.

1.4     ENVIRONMENTAL ASPECTS

        The project and all of the plant therein shall comply with the latest
        environmental guidelines contained within the "Geothermal Energy"
        section of the latest version of the "Industrial Pollution Preventions
        and Abatement Handbook" published by the World Bank Environment
        Department in collaboration with the United Nations Industrial
        Development Organisation and United Nations Environmental Programme
        current at the Effective Date of this Agreement, except wither KPLC
        provide written agreement to variations or where other more onerous
        requirements are imposed within this Agreement.


                                       55



        All equipment will be designed and constructed to minimise the
        environmental impact.

        The Seller shall give consideration to visual impact, wildlife habitat
        and temporary disturbance during construction, maintenance and
        operation. The Seller will produce and abide by a detailed statement on
        the manner in which the construction and operation will avoid or
        mitigate adverse effects on the environment including the aspects listed
        below which have been identified as requiring specific attention. Seller
        shall be especially sensitive to the National Park status of the land
        within which the Licence Area is located.

        (a)  AIR QUALITY

             Water vapour and gases (especially hydrogen sulphide) will be
             dispersed so as to avoid concentrations at ground level which are
             unacceptable as to personal safety, smell and condensate spray.

        (b)  LIQUID AND SOLID WASTES

             Liquid drilling wastes will be ponded. Residual quantities of
             liquid and solid wastes will be treated and/or removed to allow
             Site restoration. Drainage of surface water will be arranged to
             avoid the risk of erosion of the light volcanic soils.

             Spent geothermal water shall be reinjected into the ground at
             points which cause minimal disturbance to the geothermal reservoir
             and which comply with the geothermal licence.

        (c)  LAND DISTURBANCE

             Earthworks shall be kept to a minimum and so managed as to avoid
             soil erosion and to achieve permanent restoration.

             Well sites and the Plant shall be fenced but pipelines shall be
             designed to allow easy movement of animals including giraffes and
             other wildlife across the Licence Area.

        (d)  VISUAL ASPECTS

             As far as practicable, visual changes to the landscape shall be
             minimised. Consistent with safety and other engineering needs,
             Seller shall select locations, shapes and colours which merge into
             or enhance the appearance of the area including the growing of
             trees to soften the effect of the Plant structures.

        (e)  NOISE

             In addition to limiting steady and intermittent levels of noise to
             recognised safety levels for humans, Seller shall ensure that the
             unusually quiet nature of


                                       56



             the National Park and the susceptibility of wildlife to high noise
             levels are recognised in the design of the Plant and its facilities
             and the operating procedures.

             The noise limits at the Early Generation Facility and Plant
             boundary fencing shall be in accordance with the Environmental
             Impact Assessment.

1.5     PROJECT PROGRAMMING

        The Seller shall submit a detailed schedule showing key activities and
        the timetable necessary to achieve completion of the programme of work.
        The programme of work will include the design, manufacture,
        construction, commissioning and any planned maintenance for the complete
        development. During the Appraisal Period the Seller shall submit a
        report every two (2) months to KPLC or its appointed representative
        detailing the progress of the appraisal process and an estimated
        completion date. During the construction period of both the Early
        Generation Facility and the Plant the Seller will submit monthly reports
        to KPLC or its appointed representative to give the best estimated time
        to completion and demonstrate that all reasonable measures are being
        taken to maintain that schedule.

1.6     QUALITY ASSURANCE REQUIREMENTS:

        (a)  QUALITY SYSTEM

             Seller shall have a certified Quality System that meets the
             requirements of the International Standards Organisation standard
             ISO 9000 series of standard or equivalent.

             The Seller shall provide details to KPLC of a programme to ensure
             that the Early Generation Facility and the Plant operates to the
             standards, which programme shall include details of measures to
             monitor performance against such standards under surveillance, at
             least three (3) months prior to the start of construction.

             At least three (3) months prior to the Early Generation
             Commissioning Date and again three (3) month prior to the Plant
             Commissioning Date a plan containing the applicable procedures,
             design, verification, plans and inspection test plans for the Early
             Generation Facility and Plant, as the case may be, shall be
             submitted to KPLC. KPLC reserves the right to examine any
             procedures referred to in the plan and to audit the Seller against
             the requirements of the plan at any time.

             Three (3) copies of all appropriate quality records as required by
             applicable codes and standards shall be submitted to KPLC or its
             appointed representative for review prior to or concurrent with the
             arrival in Kenya of all materials and equipment required for the
             Project.


                                       57



        (b)  INSPECTION AND TESTING

             The Early Generation Facility and the Plant shall undergo
             inspection and testing during manufacture, erection and on
             completion for verification that the components satisfy all the
             requirements as specified. All inspection and testing shall be
             conducted in accordance with the applicable codes and standards.
             The Seller shall consider the provisions specified as minimum
             requirements and also use its own experience in determining
             requirements for additional inspection and testing that it
             considers necessary. KPLC shall have the right to inspect any
             records of this inspection or testing.

2.      CIVIL ENGINEERING AND CONSTRUCTION

2.1     GENERAL

        Where a building, detail, material or other item is not covered by this
        specification then it shall be based on accepted building practice using
        appropriate high quality materials.

2.2     SITE PREPARATION

        The Seller will conduct a pre-construction survey of the Licence Area.
        The survey shall demonstrate that all work for the Early Generation
        Facility, the Plant and the steam field, including construction
        requirements, lies within the Licence Area.

2.3     DWELLINGS

        The Seller will provide all accommodation or dwellings required for the
        construction and operation phases. Dwellings are not permitted within
        the National Park.

3.      STEAMFIELD

3.1     DRILLING, WELL CONTROL, ABANDONMENT

        Well design materials and drilling practices shall comply generally with
        relevant petroleum industry standards including API codes modified for
        geothermal conditions as contained in [NZSI 2403:1991 Code of Practice
        for Deep Geothermal Wells] and with the requirements of the Seller's
        geothermal licence.

        At all times during its life ever well shall be so operated, worked over
        or repaired externally as to mitigate the effects of corrosion, erosion
        and other weaknesses. Downhole and surface inspections shall be made as
        required in the geothermal licence to ensure safety for persons, surface
        property and reservoir competence.

        Before drilling or workovers commence the Seller shall provide to and
        have agreed by the KPLC detailed programmes of work. Wells which are no
        longer useful or safe shall be cemented and abandoned in the manner
        specified in [New Zealand Standard NZSI 2402] or as otherwise agreed
        with the KPLC.

        Unproductive wells shall be sealed and left in a condition agreed with
        KPLC.


                                       58



        If following the Appraisal Works no further development is to be
        undertaken all wells shall be left in a safe condition as agreed by KPLC
        at the time.



3.2     STEAM AND WATER SYSTEMS

        The layout, sizing and optimisation of the pipework and associated
        equipment will be undertaken by the Seller. For overland piping thermal
        insulation complete with cladding shall be installed to limit the
        surface temperature to 50 DEG C.

        The following standards shall be used:

        Pressure Vessel   American Society of Mechanical Engineers standard
                          ASME VIII;

        Piping            American National Standards Institute standard
                          ANSI B31.1;

        Valves            SME 16.4


        The geothermal fluid extracted from the resource shall be quantified for
        the purpose of resource monitoring and commercial reasons. The
        pressures, temperatures and flows for both steam and separated water
        shall be logged on a continuous basis. Regular chemical analyses shall
        also be conducted and logged.

4.      EARLY GENERATION FACILITY AND PLANT

4.1     GENERAL REQUIREMENTS

        (a)  GENERAL

             The design and construction of the Early Generation Facility and
             the Plant shall meet the performance requirements set out herein.
             Adequate design margins shall be included to allow for normal
             deterioration of plant performance between overhauls and
             de-scaling. All equipment used shall be new plant of proven design
             suitable for operation under the environmental conditions found at
             the geothermal site.

        (b)  DESIGN LIFE AND AVAILABILITY

             The Early Generation Facility, the Plant and all components shall
             be designed for the following minimums:

             Design Life 25 years

             Average Annual Unit Availability Factor over the Term - for the
             Early Generation Facility - 92%, and for the Plant - 96%

             where:


                                       59





             Availability Factor = Available Hours x 100
                                   ---------------------
                                           Period

             Period Hours        = 8,760

             Available Hours     = Period hours minus planned and unplanned
                                   outage hours


             The high availability specified above shall be achieved with the
             use of standby equipment (redundancy) and design measures to give
             extended periods of operation between cleaning/planned maintenance
             shut-downs.

4.2     MECHANICAL EQUIPMENT

        (a)  ROTATING EQUIPMENT

             Steam turbines shall be designed manufactured and tested to
             International Electrotechnical Commission standard IEC 45 or
             equivalent applicable code and all referenced standards. The
             turbines shall be capable of operating for at least 15 minutes at
             no load. The turbines shall be capable of stable automatic
             transition to no load operation following disconnection from KPLC's
             System. Turbines shall be designed to operate under all variations
             of chemical and physical characteristics of geothermal steam.

             For the evaluation of the performance test ASME steam tables shall
             be used.

             For turbines using motive fluids other than steam the design
             principles for steam turbines as defined in the referenced
             standards shall be adopted where appropriate. These turbines shall
             comply with the performance requirements specified for the steam
             turbine, i.e. capability of operating for at least 15 minutes at no
             load and stable automatic transition to no load operation following
             disconnection from KPLC's System.

             Pumps shall be designed, manufactured and tested to Hydraulic
             Institute Standards or AWWA as applicable.

        (c)  PRESSURE VESSELS AND PIPING

             The following standards shall be used:

             Pressure Vessel   American Society of Mechanical Engineers standard
                               ASME VIII;

             Piping            American National Standards Institute standard
                               ANSI B31.1;

             Valves            American Society of Mechanical Engineers standard
                               ASME 16.4


                                       60





        (d)  HEAT EXCHANGERS

             The following standards shall be used:

             Condenser                 Heat Exchanger Institute;

             Cooling Tower             CTI Codes/Civil building codes;

             Tubular Heat Exchangers   Tubular Exchangers Manufacturers
                                       Association Standard TEMA class C


4.3     CONTROL, INSTRUMENTATION AND ELECTRICAL EQUIPMENT

        (a)  OUTLINE OF ELECTRICAL REQUIREMENTS

             The generators of the Early Generation Facility shall be connected
             to KPLC's System at the Early Generation Interconnection Point. The
             interconnector shall consist of a single overhead transmission line
             at an agreed voltage to be built by KPLC to transfer the full
             output from the Early Generation Facility. The Seller may propose
             suitable designs for the interconnection including arrangements for
             generators, auxiliary supplies and interconnector switching. The
             design shall comply with existing KPLC design standards and
             criteria and enable the output of each generator to be controlled.
             A single line diagram is given in Figure 4.

             The characteristics of the KPLC system are as follows:



             Nominal rated voltage                   33 kV;

             Operating voltage range                 + 10%;

             Nominal frequency                       50 Hz;

             Operating frequency range               + 2.0 Hz

             Max prospective short-circuit current   40 kA (rms, symmetrical)


             The main generators of the Plant shall be connected via individual
             step up transformers, with no load tap chargers, to a high voltage
             interconnector to the Olkaria II substation (the substation to be
             constructed by KPLC).

             The interconnector shall consist of a single circuit rated to
             transfer the full output from the Plant. The interconnector shall
             be constructed at 220 kV.

             One bay will be provided at the 220 kV Olkaria II substation by
             KPLC and the Seller will propose suitable designs for the
             interconnection including arrangements for voltage transformation
             and interconnector switching. A single line diagram is given in
             Figure 3.

             The characteristics of the KPLC 220kV system ("System
             Characteristics") are as follows:


                                       61





             Nominal rated voltage                      220 kV;

             Operating voltage range                    +10%;

             Nominal frequency                          50 Hz;

             Operating frequency range                  + 2.0 Hz;

             Maximum prospective short-circuit current  40 kA (rms, symmetrical)

        (b)  GENERATORS AND ASSOCIATED CONTROL EQUIPMENT


             Each generator of the Early Generation Facility shall be rated on a
             continuous running duty basis, duty Type SI, for a design power
             factor of 0.85 lagging to 0.9 leading. The maximum continuous
             rating of the Early Generation Facility after completion of the
             third energy converter unit, is approximately 12 MW and shall be
             the output available at the Delivery Point at rated voltage,
             frequency and power factor.

             Each generator of the Plant shall be rated on a continuous running
             duty basis, duty Type SI, for a design power factor of 0.8 lagging
             to 0.9 leading. The maximum continuous rating was originally
             expected to be 64 MW but, was determined to be 48 MW pursuant to
             the completion of the Appraisal Works. All references to 64 MW from
             now on in these Schedules shall be taken to mean the assumed value
             and may be subject to change in light of the Appraisal Works and
             shall be that output available at the Delivery Point at rated
             voltage, frequency and power factor.

             All generators shall be equipped with a continuously acting fast
             response automatic excitation system of either brushless or static
             type with a high initial response characteristic (excitation system
             voltage response time of 0.1 second or less).

             The generator automatic voltage regulators shall be capable of
             maintaining terminal voltage to an accuracy of + 0.5%, relative to
             a constant reference value, adjustable over the range + 10%, to
             ensure adequate steady state stability.

             The generator short circuit ratio at rated MVA shall not be less
             than 0.5.

             Automatic synchronising equipment shall be provided for the
             generator circuit breakers. Manual synchronising, complete with
             check synchronising facilities relays shall be provided for the
             generators/step up transformers.

        (c)  POWER TRANSFORMERS

             The generator step up transformers of the Plant shall be rated for
             maximum duty. They shall be fitted with on load tap changers with a
             tapping range such as to permit maximum export with the generator
             at rated voltage and 0.85 lagging power factor, with KPLC's System
             operating at a voltage of 220kV.


                                       62



        (d)  EMERGENCY AND MAINTAINED POWER SUPPLIES

             The Seller shall ensure that sufficient and reliable standby power
             supplies are available during loss of normal power supplies, such
             that continuous operation of all equipment which may be required
             during such periods can be maintained.

        (e)  EARTHING AND LIGHTING PROTECTION

             The Seller shall include a complete and integrated earthing and
             lightning protection system for the overall Site.



        (f)  COMMUNICATIONS

             Communications with KPLC shall be via telephone line to Olkaria I
             in accordance with its requirements. The Seller shall provide one
             telephone extension and one fax extension on each of KPLC's control
             networks. These telephones shall not be interconnected to any
             system which is connected to the public telephone system.

             Provisions shall be made by the Seller for data interconnections to
             KPLC's SCADA system.

             The Seller will install a dedicated computerised system for
             acquisition of plant data and calculation of all plant
             characteristics which are related to power generation and
             efficiency of conversion, to enable payments from KPLC to the
             Seller to be calculated. The Seller shall also log all dispatch
             requirements. A remote visual display unit, terminal and printer
             capable of interrogating the computer system shall be provided to
             KPLC's premises at Juja Road, Nairobi, communicating via telephone
             modem.

4.4     OPERATING CHARACTERISTICS

4.4.1   EARLY GENERATION FACILITY

        (a)  UNIT STARTS

             The notice required by the Seller to start up a binary energy
             converter Unit (BEC) of the Early Generation Facility will vary
             according to the length of time that the turbine generator of the
             binary energy Converter has been shut down. The Early Generation
             Facility shall be able to start up the various components within
             the following time periods:

             SCOPE OF SHUTDOWN           NOTICE REQUIRED TO SYNCHRONISE

             Early Generation Facility   BEC 1 hour

             Steam Field                 6 hours

             Wells                       12 hours



                                       63



        (b)  UNIT LOAD RAMPING RATE

             The maximum Unit load ramping rate during synchronisation and a
             load to full load under normal conditions shall be no more than 10%
             of Unit rated capacity per minute.

        (c)  STEP LOADING

             Any Unit shall be able to accept an instantaneous load variation of
             5% of rated capacity.

        (d)  LOAD REJECTION

             Any Unit and the Early Generation Facility must remain in a safe
             condition following a sudden full load rejection and must be
             capable of re-synchronisation within 30 minutes.

        (e)  FREQUENCY LIMITATION

             The frequency limitation of the Early Generation Facility for
             continuous operation is between the range 48.0 and 52.0 Hz.

        (f)  POWER FACTOR

             Each unit is capable of operating at Rated Capacity with a
             generation power factor measured at the generator terminals in the
             range of 0.85 lagging to 0.90 leading.



        (g)  VOLTAGE LIMITS

             The Early Generation Facility shall be capable of operating with
             the variation of +/- ten percent (10%) at the generator terminals.
             The Early Generation Facility will automatically trip if the
             voltage exceeds this range.

4.4.2   PLANT

        (a)  UNIT STARTS

             The notice required by the Seller to start up a turbine generator
             unit will vary according to the length of time that the turbine
             generator has been shut down. The Plant shall be able to start up
             the various components within the following time periods:

             SCOPE OF SHUTDOWN    NOTICE REQUIRED TO SYNCHRONISE

             Generating Plant     3 hours from cold, 1 hour from hot

             Steam Field System   6 hours

             Wells                12 hours



                                       64



        (b)  UNIT LOAD RAMPING RATE

             The maximum Unit Load ramping rate during synchronisation and
             loading to full load under normal conditions shall be no more than
             ten percent (10%) of Rated Capacity per minute.

        (c)  STEP LOADING

             Any unit shall be able to accept an instantaneous load variation of
             five percent (5%) of rated capacity.

        (d)  LOAD REJECTION

             Any Unit and the Plant must remain in a safe condition following a
             sudden full load rejection and must be capable of
             re-synchronisation within thirty (30) minutes.

        (e)  FREQUENCY LIMITATION

             The frequency limitation of the Plant for continuous operation is
             between the range forty eight (48.0) and fifty two (52.0) Hz.

        (f)  POWER FACTOR

             Each unit is capable of operating at Rated Capacity with a
             generation power factor measured at the generator terminals in the
             range 0.85 lagging to 0.90 leading.

        (g)  VOLTAGE LIMITS

             The Plant shall be capable of operating with variation of +/- ten
             percent (10%) of the voltage on the high voltage terminals of the
             step up transformers with no-load tap changer in operation. The
             Plant will automatically trip if the voltage exceeds this range.


                                       65



      PART B: THE SELLER'S CONNECTION FACILITIES INCLUDING THE TRANSMISSION
                 INTERCONNECTOR AND KPLC'S CONNECTION FACILITIES

1    TRANSMISSION INTERCONNECTOR

The Seller shall construct a single circuit Transmission Interconnector between
the Plant and the KPLC's Connection Facilities which are located at the Olkaria
II power station 220 kV switchyard. The Transmission Interconnector shall be
designed in accordance with existing KPLC design standards and criteria. The
design criteria considering line design basis, protection and communication
requirements, including inter-tripping requirements are set out in Part C of
this Schedule 2.

2    GENERATING UNIT PROTECTION DEVICES

The Units shall be equipped with the following protection devices and KPLC and
the Seller shall agree the necessary settings for these:

(i)   Stator Earth Fault;

(ii)  Negative Phase Sequence;

(iii) Step up transformer over current and earth fault; and

(iv)  High voltage busbar protection (if appropriate).


                                       66





              PART C: DESIGN CRITERIA - TRANSMISSION INTERCONNECTOR

1 - TEMPERATURE LIMITS AND WIND LOADINGS



ITEM   DESCRIPTION                                                                    DETAIL
----   -----------                                                                 -----------

1.     TEMPERATURES

1.1    Minimum temperature of conductors                                           DEG. C   -1

1.2    Maximum temperature of conductors                                           DEG. C   75

1.3    "Everyday" temperature of conductors                                        DEG. C   25

2.     WIND PRESSURE

2.1    Wind pressure on projected area of conductors, earth wires and insulators   N/m(2)  383

2.2    Wind pressure on projected area of members of one face of tower             N/m(2)  690



2 - FACTORS OF SAFETY



                                                                                     MINIMUM
ITEM   DETAIL                                                                         FACTOR
----   ------                                                                      -----------

CONDUCTORS

1.     Conductors  and earth  wire at final  maximum  working  tension  based on        3.0
       ultimate nominal breaking load.

2.     Conductors and earth wire in still air at everyday  temperature final            5.0
       tension based on ultimate nominal breaking load.

3.     Anchor clamps and mid-span joints based on conductor or earth wire              0.95
       ultimate nominal breaking load.

INSULATORS AND FITTINGS

4.     Tension set failing load based on conductor maximum working tension              3.0

5.     Suspension set failing load based on the resultant of maximum vertical           3.0
       and transverse loadings under normal working conditions.

SUPPORTS

6.     Steel towers under normal working conditions.                                    2.5

7.     Steel towers under broken wire conditions.                                      1.25

8.     Foundations under normal working conditions.                                     2.5

9.     Foundations under broken wire conditions.                                        1.5



                                       67



3 - MINIMUM CLEARANCES

The following are the minimum clearances between live conductors and other
objects, which correspond to the condition of maximum sag of conductor either in
still air or at maximum swing condition.





                                                                                                 CLEARANCE
ITEM      DESCRIPTION                                                                              220 kV
----      -----------                                                                            ---------

3.1       Minimum clearances from Conductor in m:

   (i)    to normal ground                                                                          7.5

   (ii)   to metal clad or roofed  buildings,  or other  buildings or structures  upon which a      5.2
          man may occasionally stand

   (iii)  to electric power line wires (line or earth)                                              4.0

   (iv)   to telephone lines                                                                        4.0

   (v)    to paved roads                                                                            8.5

   (vi)   to railways                                                                               8.5

   (vii)  to be added to the above clearances to allow for conductor creep (at mid span)            0.6

3.2       Minimum clearance from live metal to support steelwork on suspension supports in mm:

   (i)    from 0-25 DEG. swing                                                                     2200

   (ii)   from 25 DEG. to 45 DEG. swing                                                            2100

3.3       Assumed maximum  transverse swing from the vertical of suspension  insulator strings    45 DEG.
          on straight line supports

3.4       Minimum clearance from live metal to earthed metal at tension supports in mm:

   (i)    in still air                                                                             2200

   (ii)   jumper loops under 25 DEG. swing                                                         2100

3.5       Assumed maximum angle of swing from the vertical of jumper loops                        25 DEG.

3.6       Maximum shielding angle of earth wire (in still air) on conductor at tower               0 DEG.




                                       68





4 - BROKEN WIRE CONDITIONS

                                    MAXIMUM NUMBER OF COMPLETE PHASE OR EARTH
ITEM   TOWER TYPE                   CONDUCTORS BROKEN
----   ----------                   --------------------------------------------
4.1    Suspension, Single Circuit   Any one phase or one earth wire (tension
                                    reduced to 70% of maximum working tension
                                    for broken phase only).

4.2    Suspension, Double Circuit   Any one phase and one earth wire or any two
                                    phases (tension reduced to 70% of maximum
                                    working tension for broken phases only)

4.3    All other tower types        Any two wires, phase or earth, at maximum
                                    working tension



                                       69





5 - SPAN LENGTHS

                                                                    SPAN LENGTHS
ITEM   DESCRIPTION                                                      (m)
----   -----------                                                  ------------
5.1    Basic (design) span                                               370

5.2    Wind span (Suspension and           (i)  Normal condition         410
       Angle Tension towers)
                                           (ii) Broken wire              310

       Wind span (Terminal towers)         Normal condition              220

5.3    Weight span for Suspension towers   (i)  Normal condition         740
                                           (ii) Broken wire              560

       Angle Tension towers                (i)  Normal condition        1110
                                           (ii) Broken wire              840
       Terminal towers                     Normal condition              840



                                       70



6 - SUPPORT AND FOUNDATION DESIGN DATA

ITEM    DESCRIPTION                                                       DETAIL
-----   -----------                                                       ------
6.1     SUPPORTS

6.1.1   Maximum ration of  unsupported  length of steel  compression
        members to their least radius of gyration (L/R):

(a)     Main members                                                        120

(b)     Bracings                                                            200

(c)     Redundants                                                          250

(d)     Bracings Loading in tension only                                    350


                                       71





7 - SUPPORT AND FOUNDATION DESIGN DATA



                                               LIGHT         HEAVY                  WATER-
                                             CONCRETE      CONCRETE      SOFT       LOGGED       ROCK
ITEM    DESCRIPTION                            BLOCK         BLOCK       ROCK        SOIL       ANCHOR
-----   -----------                          --------      --------      ----       ------      ------

7.2     FOUNDATIONS

7.2.1   Assumed mass of earth resisting         1600          1350       1900         750          20
        uplift (kg/m(3))

7.2.2   Assumed angle to vertical of              30 DEG.       30 DEG.    20 DEG.     30 DEG.     15 DEG.
        frustum of earth resisting uplift

7.2.3   Assumed mass of concrete resisting      2300          1850       2300        1350        2300
        uplift (kg/m(3))

7.2.4   Assumed ultimate earth pressure          370           185       1100         150        2000
        for standard foundation under
        specified loadings, including
        factors of safety (kN/m(2))

7.2.5   Ultimate adhesion value between          0.7           0.7        0.7         0.7         0.7
        galvanised steel and concrete,
        including factor of safety
        (N/mm(2))

7.2.6   Ultimate lateral earth pressure,         100           100        100          --         100
        including factor of safety (for
        chimney design) (kN/m(2)/m)

7.2.7   Ultimate plain concrete bearing         13.8          13.8       13.8        13.8        13.8
        stress (N/mm(2))

7.2.8   Minimum portion of sub loads to be        50%           50%        50%         50%         50%
        allowed for in the design of sub
        cleats

7.2.9   Shear stress in rock (kN/m(2))            --            --         --          --          50




                                       72





8 - INSULATORS 220 kV LINES



                                                    DETAIL
ITEM   DESCRIPTION                                SUSPENSION            TENSION
----   -----------                            ------------------   ------------------

8.1    Insulator Type                         Cap & Pin            Cap & Pin

8.2    Insulator Material                     Glass or Porcelain   Glass or Porcelain

8.3    Minimum No. of units per string        15                   16

8.4    Minimum Spacing                        146 mm               146 mm

8.5    Lightning Impulse                      1050 kV              1050 kV
       Withstand voltage of complete string
       (minimum sea level value)

8.6    Minimum creepage
       distance of String (normal)            5664                 5664 mm*
       (in quarry areas)                      6124                 6125



*    Tension strings shall achieve those values with one unit removed from the
     string.


                                       73



9 - 220 kV CIRCUIT BREAKER

A Circuit Breaker shall be installed on the outgoing 220 kV line and dedicated
for Protection and Control of the Line.

9.1     TYPE

The Circuit breaker shall be of the SF6 type with individual self contained
spring operated mechanism.

Emphasis is placed on the need for reliability of design in order to give long
continuous service with low maintenance costs. In this respect, spring operated
mechanisms are the preferred type.

9.2     RATINGS

1200 A continuous rating and 31.5 kA, 3 sec. Circuit Breaker.

9.3     OPERATING DUTY AND PERFORMANCE

GENERAL

The requirements of IEC 60056 in respect of type tests service operation and the
making and breaking of faulty currents shall apply to all types of circuit
breakers. Designs shall be suitable for interrupting three-phase ungrounded
faults.

(ii)    TEST CERTIFICATES

Circuit breakers shall be covered by test certificates issued by a recognized
short-circuit testing station certifying the operation of the circuit breaker at
duties corresponding to the rated breaking capacities for the circuit breaker.

The test duty shall not be less onerous than the requirements of the standard.
Test certificates or equivalent shall be submitted with the tender.

(iii)   RATE-OF-RISE OF RESTRIKING VOLTAGE

Where not specifically stated in the test certificates submitted with the
Tender, the Tenderer shall certify that the TRV to which the circuit breaker was
subjected during the short circuit tests was the most severe condition that
could be imposed by the available test plant for a first phase-to-clear factor
of 1.5.

Any device incorporated in a circuit breaker to limit or control the rate of
rise of restriking voltage across the circuit breaker contacts shall likewise be
to the Engineer's approval and full description of any such device shall be
given.


                                       74



(iv)    RECLOSURE DUTY

At 220 kV breakers controlling transmission lines and transformer feeders shall
be suitable for high speed single phase and delayed three-phase auto reclosure.

Circuit breakers may be subject to several single shot auto reclosing duty
cycles within quick succession upon the occurrence of multiple faults coupled
with short reclaim timer settings. The Seller shall state the minimum time
interval permissible between each auto reclose duty at rated short circuit
current and advise the number of reclosing operations allowable before lockout
and maintenance becomes necessary.

The main contractor shall ensure the circuit breaker requirements are embodied
in the auto-reclose protection scheme.

(v)     INTERRUPTING DUTIES

In addition to the requirements of IEC 60065 for interrupting terminal faults
circuit breakers shall be capable of coping with the interrupting duties
produced by the switching of low inductive currents associated with reactors or
transformers magnetizing currents, or by the switching of capacitor currents
associated with overhead line charging, cable-charging or capacitor banks as may
be applicable. Circuit-breakers for these duties shall be of the restrike-free
type only.

Circuit breaker shall be capable of interrupting currents associated with
short-line faults and the out of phase switching conditions that may occur in
service.

The Seller should include a statement of the accumulative breaking capacity
which the circuit breakers are capable of before maintenance is required.

(vi)    BREAK TIME

In respect of 220 kV circuit breakers attention is drawn to Clause 14.3.

(vii)   INSULATION CO-ORDINATION

The insulation strength across the open circuit breaker shall be at least 15 per
cent greater than the line to ground insulation strength for all impulse,
switching surge and power frequency voltage conditions.

9.4     OPERATING MECHANISMS

Circuit breakers mechanisms shall be "trip free" as defined in IEC 60056-1. It
is recognized that it may be necessary for contacts to close momentarily prior
to opening to ensure satisfactory current interruptions.

Each part of the operating mechanisms shall be of substantial construction,
utilizing such materials as stainless steel, brass or gunmetal where necessary
to prevent sticking due to rust or corrosion. The overall designs shall be such
as to reduce mechanical shock to a minimum and shall prevent inadvertent
operation due to fault current stresses, vibration or other causes.


                                       75



An approved mechanically operated indicator shall be provided on each circuit
breaker operating mechanism to show whether the circuit breaker is open or
closed. Each phase shall incorporate a mechanical indicator or other approved
means of position indication where operating mechanism designs do not utilize
mechanical coupling between phases.

220 kV circuit breaker mechanisms shall be provided with duplicate trip coils in
order to facilitate duplication of trip coil initiation.

Where circuit breakers comprise three independent units as in this case it shall
be possible to make independent adjustments to each unit. For three phase
operation the three units shall make and break the circuits simultaneously. In
the event of any phase failing to complete a closing operation, provision shall
be made for automatic tripping of all three phases of the circuit breaker. This
scheme shall be inbuilt within the circuit breaker. Indications for operation of
this condition shall be indicated locally, remotely and on SCADA.

Power closing mechanisms shall be recharged automatically for further operations
as soon as the circuit breaker has completed the closing operation and the
design of the closing mechanism shall be such that the circuit breaker cannot be
operated inadvertently due to external shock forces resulting from short
circuits, circuit breaker operation, or any other cause.

If a circuit breaker closing mechanism is not fully recharged for further
operation within a pre-determined time after closing cycle, the mechanism shall
be locked out and an alarm initiated.

The circuit breaker shall be provided with slow acting manually powered
operating devices for inspection and maintenance purposes only. It shall not be
possible to slow close a circuit breaker when in normal service condition.

9.5     OPERATING CUBICLES

Circuit breaker operating mechanism, auxiliary switches and associated relays,
control switches, control cable terminations, and other ancillary equipment
shall be accommodated in sheet steel vermin-proof and weather proof cubicles.
Where appropriate the cubicles may be free standing.

Cubicles shall be of rigid construction, preferably folded by alternatively
formed on a frame work of standard rolled steel sections and shall include any
supporting steel work necessary for mounting on the circuit breaker or on
concrete foundations.

Bolts or carriage keys shall not be used to secure the panels or doors. All
fastenings shall be integral with the panel or door and provision made for
locking. Doors and panels shall be rigid and fitted with weather proof sealing
material suitable for the climatic conditions specified.

Cubicle shall be well ventilated through vermin-proof louvers comprising a brass
gauze screen attached to a frame and secured to the inside of the cubicle.
Divisions between compartments within the cubicles shall be perforated to assist
air circulation. In addition, an anti-condensation heater of an approved type
shall be provided and controlled by a single pole switch mounted within the
cubicle.


                                       76



Access doors or panels shall be glazed where necessary to enable instruments to
be viewed without opening the cubicles. The arrangement of equipment within the
kiosk shall be such that access for maintenance or removal of any item shall be
possible with the minimum of disturbance of associated apparatus.

Circuit breaker control position selector and circuit breaker operating control
switches as specified shall be installed in the cubicle. Circuit breaker control
from this position will be used under maintenance and emergency conditions only.

An approved schematic diagram of the part of the control system local to the
circuit breaker, identifying the various components within the cubicle and on
the circuit breaker and referring to the appropriate drawings and maintenance
instructions, shall be affixed to the inside of the cubicle access door. The
diagram shall be marked on durable non-fading material suitable for the
specified site conditions.


                                       77



10 - DISCONNECTORS AND EARTHING SWITCHES

Two 220 kV Disconnectors shall be installed, one on either side of the outgoing
220 kV Circuit Breaker. The disconnectors shall be motorized.

The Disconnector shall be rated at 1200 A, continuous rating and 31.5 kA, 3 sec.
withstand.

The disconnector on the Line side shall be equipped with an Earth Switch,
mechanically coupled or interlocked with the main disconnector so that the
earthing switch and main disconnector cannot be closed at the same time.

Disconnecting and earthing devices shall be in accordance with IEC 60129.

The disconnectors shall preferably be of the single throw double air break
centre rotating post type or of the double rotating post type with single air
break and shall be subject to approval. Circuit disconnecting switches shall be
rated at 1200 A continuous rating.

Disconnecting switches shall be designed for live operations and will not be
required to switch current other than the charging current of open bus bars and
connections or load currents shunted by parallel circuits.

Service conditions require that disconnecting switches shall remain alive and in
continuous service for periods of up to two years in the climatic conditions
specified and without operation or maintenance. The contacts shall carry their
rated load and short circuit currents without overheating or welding and at the
end of the two year period the maximum force required at the end of the
operating handle to open a 3-phase disconnector shall not exceed 340N.

The earthing switch, when in closed position shall be capable of carrying the
rated short time current for three seconds without the contacts burning or
welding. The Earth Switch shall be interlocked with the Line CVTs such that it
shall not be possible to close the earth switch when the line is energized.

Disconnecting devices shall be interlocked with circuit breakers and
disconnectors as necessary to prevent the possibility of making or breaking load
current.

The Disconnectors and the Earth switch shall be equipped with Electrical
Interlocks to ensure safe operation. Each Disconnector and the Earth Switch
shall be equipped with a solenoid which will normally be de-energised thereby
mechanically blocking the operation of the Disconnector or the Earth switch.
When all the conditions are right for safe operation of the Disconnector or the
Earth switch, the solenoid shall be energized via a push button switch mounted
on the disconnector/earth Switch control box, thereby allowing the Disconnector
or Earth switch to be operated to the closed of open position. The solenoid
shall only require to be energized at the start of the close or open operation
and shall not be required to remain energized in order to complete the close or
the open operation.

Operation of the Circuit Breaker shall not be permitted when the associated
Disconnector Switches are under operation. Interlock to be achieved by use of
auxiliary switches.


                                       78



Also a mechanical Interlock shall be provided between a Disconnector and the
associated Earth Switch.

Disconnector operation mechanisms shall be of robust construction, carefully
fitted to ensure free action and shall be unaffected by climatic conditions at
site. Mechanism shall be as simple as possible and comprise a minimum of bearing
and wearing parts. Approved grease lubricating devices shall be fitted to al
principal bearings which are not of self lubricating type. The mechanism shall
be housed in a weatherproof enclosure complete with auxiliary switches, terminal
blocks and cable gland plates. All steel and malleable iron parts including the
supporting steelwork shall be galvanized.

The alignment and timing of primary and secondary contacts shall be achieved
with ease. Once achieved, continuous operation of the disconnector without
losing the alignment or timing shall be guaranteed.


                                       79





11- VOLTAGE TRANSFORMERS

Voltage transformers shall be of the capacitor type and shall comply with IEC
60044-2 and the requirements of this specification.

Capacitor type transformer shall be suitable for use as line couplers for power
line carrier communication systems.

Ratings:
Rated Primary Voltage:     220 kV/[X]3
Rated Secondary Voltage:   110 V/[X]3


The rated Burden and Class shall be suitable for the connected Protection Relays
and other devices.

Separate sets of MCBs shall be provided at the CVT for:
Main 1 protection
Main 2 protection
Instruments, disturbance recorder, fault locator, etc.
Check Synchronizer Relay.

The Main 1 Protection and Main 2 Protection circuits shall be segregated in
separate multicore cables from the VT to the Protection panels.

A VT failure Alarm shall be provided for each set of MCBs.

Voltage transformers shall be provided complete with galvanized steel supporting
structures such that the earthed end of all porcelain insulators is not less
than 2440 mm above ground level.


                                       80



12 - CURRENT TRANSFORMERS

Current transformers shall comply with IEC 60044-1 and the requirement of this
specification.

Primary winding conductors shall be not less than 100 sq. mm section and shall
have a one second short time current rating not less than that of the associated
switchgear. Secondary windings of each current transformer shall be earthed at
one point only, in the relay panel.

Magnetisation and core loss curves and secondary resistance values shall be
provided for each type and range of current transformer.



Ratings:

CT ratio:   1500-800-300/ 1 A, to match the remote end CTs
Core 1:     15 VA, 5p20 for Main 1 Protection
Core 2:     15 VA, 5p20 for Main 2 Protection
Core 3:     15 VA, 5p20 for Back-up Protection and Circuit Breaker
            Failure Protection
Core 4:     15 VA, Cl 0.2 for Energy Metering
Core 5:     For Busbar Differential Protection. Seller to specify to match
            other CTs in the Differential Scheme


Current transformers for balance protective schemes, including neutral current
transformers where appropriate, shall have identical turns ratio and shall have
magnetization characteristics to the approval of KPLC for each specific
instance. Where an existing balanced protective system is being extended, the
Seller shall ensure that any additional current transformers are correctly
matched on the existing equipment.

The Seller shall ensure that the capacity of the current transformer provided is
adequate for operation of the associated protective devices and instruments.

The CT cores for Main 1 and Main 2 protection shall be segregated in separate
multicore control cables from the current transformer through to the protection
panels.

Where double ratios are specified it shall be possible to select either ratio
for each winding without alteration to the number of primary turns. A label
shall be provided at the secondary terminals of the current transformer
indicating clearly the connection required for either ratio. These connections
and the ratio in use shall be shown on the appropriate schematic and connector
diagram.

The Seller shall provide details of his method of calculating the outputs of the
current transformers for each type of protection specified and shall submit
calculations for all current transformers for approval by the KPLC before
starting manufacture.


                                       81



13 - SURGE ARRESTORS

Surge arrestors shall be the type employing non-linear metal oxide resistors
without spark gaps.

Arrestors shall be designed and tested in accordance with the requirements of
IEC 60099-4.

Surge arrestors shall be housed in porcelain insulators designed to withstand
extremes of the environment. The insulation shall have a minimum creepage
distance of 25 kV/mm. Porcelain shall comply with IEC 60233.

The method of sealing against the ingress of moisture shall be of a type well
proven in service and the manufacturing procedures shall include an effective
leak test which can be demonstrated to the inspecting Engineer if required.

The internal components of arrestors shall be arranged to minimize radial
voltage stresses, internal corona and to ensure minimal capacitative coupling
with any conducting layer of pollutant on the outside of the porcelain housing.
Except where approved organic materials are not permitted.

Good electrical contact shall be maintained between resistor blocks, which takes
account of any thermal expansion and contraction of the block, mechanical shock
during transport and erection, by installing a well proven clamping system.

Good quality control of the manufacturing process of the resistor shall be
ensured by rigorous testing procedures. The procedures shall ensure that the
characteristics of the blocks area, and will remain within the specified limits
when new and throughout the anticipated life of the arrestors. Samples may be
selected at random by the Engineer for special tests to be agreed with the
manufacturer.

All surge arrestors shall be fitted with a pressure relief diaphragm which shall
prevent explosive shattering of the porcelain housing in the event of an
arrestor failure and the arrestor shall have been tested according to the high
and low current tests specified in IEC 60099-1.

Arrestors shall be supplied complete for installation in an outdoor switchyard
including insulating bases and surge counters, one per phase and, if applicable,
grading rings. The material used for terminals shall be compatible with that of
the conductors to which they are connected.

Each arrestor shall be identified by a rating plate in accordance with the
requirements of IEC 60099. In addition an identification mark shall be
permanently inscribed on each separately housed unit of a multi-unit arrestor so
that units can be replaced in the correct position in the event of them being
dismantled.


                                       82



14 - PROTECTION AND CONTROL

14.1   MULTICORE CABLES AND SCHEMATIC DIAGRAMS

Protection and control schemes should, in general be based on the use of a
single 1.5 sq.mm [7/0.67 mm] cores. The Multi-core cables shall have steel
Armour for mechanical protection.

This contract includes the preparation of cabling schematic diagrams, showing
the approved routing of cores in the various cables, and detailed cable
schedules and connection diagrams for all the cables associated with each item
of equipment included in the project.

14.2   RELAY GENERAL REQUIREMENTS

All relays shall operate correctly within system frequency limits 47 Hz to 51
Hz.

Relays shall be approved types complying with IEC, shall have approved
characteristics, be flush mounted in dust and moisture proof cases and shall
comply with IEC 60068 test classification 20/40/40.

Relays shall be of approved construction and shall be arranged so that
adjustments, testing and replacement can be effected with the minimum of time
and labour. Relays of the hand reset type shall be capable of being reset
without opening the case.

Electrically reset tripping relays shall be provided where necessitated by the
system of control, such as for those circuits subject to remote supervisory
control.

Relay contacts shall be suitable for making and breaking the maximum currents
which they may be required to control in normal service but where contacts of
the protective relays are unable to deal directly with the tripping currents,
approved auxiliary contactors, relays or auxiliary switches shall be provided.
In such cases, the number of auxiliary contactors or tripping relays operating
in tandem shall be kept to a minimum in order to achieve fast fault clearance
times. Separate contacts shall be provided for alarm and tripping functions.
Relay contacts shall make firmly without bounce and the whole of the relay
mechanisms shall be as far as possible unaffected by vibration or external
magnetic fields.

Relays, where appropriate, shall be provided with flag indicators, phase
coloured where applicable. Flag indicators shall be of the hand rest pattern and
shall be capable of being reset without opening the case. Where two or more
phase elements are included in one case, separate indicators shall be provided
for each element.

All protection relays shall be of the numerical type. The Numerical Relays
provided must have facilities to download information to a PC and via a modem,
to a remote Location via the available communication system. One PC and
associated Software shall be provided. Steps shall be taken to protect the
circuitry from externally impressed transient voltages which could reach the
circuitry via connections to instrument transformers or the station battery.

The routing of cables should be such as to limit interference to a minimum. Any
auxiliary supplies necessary to power solid state circuits shall be derived from
the main station battery and not from batteries internal to the protection.


                                       83



Relays with provision for manual operation from outside the case, other than for
resetting, will not be accepted.

Relays, whether mounted in panels or not, shall be provided with clearly
inscribed labels describing their application and rating in addition to the
general purpose labels.

Attention is particularly drawn to the site climate condition and relay designs
should be entirely suitable for duty under these conditions.

To minimise the effect of electrolysis, relay coils operating on DC shall be so
connected that the coils are not continuously energized from the positive pole
of the battery.

Relays shall be suitable for operation on 110 V nominal, 125 float dc systems
without the use of voltage dropping resistors or diodes.

The contractor shall provide detailed current transformer requirements for each
type of relay.



14.3   FAULT CLEARANCE TIMES

Overall fault clearance times i.e. from fault initiation to arc extinction shall
not exceed the following:

       MAXIMUM FAULT CLEARANCE TIME
       -------------------------------------------------------------
       TYPE OF FAULT                          MAXIMUM CLEARANCE TIME
                                              220 kV SYSTEM
       ------------------------------------   ----------------------
       Substation and transformer faults      110 mS

       Line faults

       (a)  Up to 72% of the line length      100 mS
            (i.e. 90% of a distance relay
            Done 1 reach assuming 80%
            Zone 1 setting

       (b)  From 72% to 100% of line length   130 mS
            Plus protection
            Signalling time


These requirements shall be fulfilled under all system conditions including
maximum dc current offset and shall include any time delay caused by the use of
capacitive voltage transformers.


                                       84



14.4   LINE PROTECTION

14.4.1 DISTANCE PROTECTION

Distance protection for 220 kV lines shall comprise one distance relay installed
by OrPower 4 in Olkaria III Substation operating in conjunction with
teleprotection channels over fibre optic circuits. The distance Protection shall
operate in a permissive overreach mode over a teleprotection signalling channel.

The distance relay shall operate for all types of phase and earth faults.
Separate phase and earth fault distance measuring elements shall be provided.
Common elements with transfer switching arrangements will not be accepted. Phase
and earth fault compensation features shall be incorporated to ensure accurate
distance measurements for all types of fault and to allow for variation in the
path of earth faults on the system.

Zones 1 and 2 shall operate only for faults in the protected direction. Under no
circumstances shall the relay operate for reverse faults even when the voltage
supplied to the relay falls to zero on all three phases. Details of methods used
for polarising relays to deal with faults close to the relaying point shall be
provided.

Zone 3 shall not be non-directional and shall be capable of being independently
off-set in both directions.

Starting shall be by impedance relays; overcurrent starting will not be
accepted. The relay characteristic shall cover the protected line plus the
longest line emanating from the remote station taking current infeed into
account.

The starting relays shall not operate during maximum power transfer. During
single phase to earth fault coinciding with maximum power transfer, only the
starting relay associated with the faulted phase shall operate.

The reach of each measuring zone and starting relay shall be individually
adjustable by suitable steps across the setting range. The characteristic angle
shall be adjustable between approximately 40 and 85 degrees.

Zone 2 and Zone 3 shall have a delay setting range of 0.1 to 1.0 second and 0.5
to 5.0 seconds respectively.

The sensitivity of the protection shall be adequate for definite operation under
minimum plant and single outage conditions and shall not exceed 30 per cent
rated current. The relay characteristic shall ensure adequate earth fault
resistance cover under all conditions.

The operating time of each zone shall be substantially independent of fault
current magnitude. The operating times shall be stated in the Schedule of
Particulars and, in addition, curves shall be provided showing the effect of
line and source impedance, fault position and operating current on the relay
operating time.


                                       85



A feature shall be incorporated to ensure instantaneous tripping in the event
that the circuit breaker is closed into a fault on a previously de-energised
line. This feature will be enabled by the absence of line voltage with an
appropriate time delay.

A monitoring system shall be provided to supervise the voltage transformer
supply to each distance relay. I the event of loss of one or more phases, the
monitoring system shall inhibit relay operation and initiate an alarm.

The distance relays shall incorporate indicators to show the zone in which the
relay tripped, the phases or phases faulted and whether operation was assisted
by a teleprotection signal. Indication must not be lost in event of a DC
auxiliary supply failure.

In addition to tripping contacts, the protection shall have, contacts for
initiating single pole and three pole auto-reclosing, fault locators, fault
recorders, signalling and alarms. The protection for the 220 kV feeder shall be
suitable for single pole tripping and for use in the single and three phase auto
reclosing scheme.

Where appropriate the protection and associated auto-reclose equipment shall
incorporated whatever means are necessary to ensure that all measuring and
starting elements in the healthy phases of the faulted line and all measuring
elements on the parallel circuit remain reset and are unaffected by the currents
which flow in the healthy phases and parallel circuit during the single phase
reclosure dead time. Additionally, the inter-phase fault measuring elements on
the faulted circuit shall be stable in the presence of a heavy close-up earth
fault. The methods used to ensure correct stability of healthy phase elements
during single phase dead times and during fault conditions shall in no way
prejudice the ability of the protection and auto-reclosing scheme to respond to
faults during the dead time and reclaim time in the manner described in Clause
14.5.

The distance protection scheme in permissive mode shall include an "echo"
feature to facilitate tripping of the local circuit breaker if a line fault
occurs when the remote end disconnector is open or the remote end distance relay
has not started. Suitable timers shall be included to prevent continuous carrier
send when the circuit breaker is open and to remove the "echo" signal after a
time, sufficient for tripping to occur, has elapsed.

The distance protection shall remain in service while the line disconnector is
open so as to afford instantaneous protection to the primary connections on the
busbar side of the line disconnector. For this purpose line disconnector
auxiliary switches shall be used to isolate the CVT connections to the distance
relay.

POWER SWING BLOCKING

The 220 kV distance relays shall incorporate power swing blocking Function
Function Characteristic, Power swing blocking shall encompass and be concentric
with the distance relay impedance starter or zone 3 characteristic. Similarly
where it is possible to shape the zone 3 or starter characteristic the power
swing blocking Function characteristic shall also be capable of similar shaping.

Where zone 3 is set reverse looking as directional mho, the power swing blocking
outer characteristic shall be capable of being set concentric with the zone 2
mho characteristic.


                                       86



Facilities shall be provided to block zones 1, 2 and 3 of the distance relay as
required.

Blocking logic shall be derived by determining the time taken for the apparent
impedance of the power swing locus to pass from the characteristic of the power
swing to the distance relay starter characteristic. Blocking shall not take
place until the apparent impedance has passed through the characteristics and
the time has expired.

The associated time delay relay shall have a setting range of 50 - 250 msecs.

The setting range of the power swing function characteristic angle shall at
least be adjustable over the same range as the distance relay zone 2 or zone 3
characteristic.

Reset times shall be short to ensure the distance relay reverts to its normal
role as soon as possible following a power swing.

Power swing blocking shall be inhibited if an earth fault occurs during a power
swing.

If the associated VT supplies are lost due to VT failure the power swing
blocking Function shall not operate.

DIRECTIONAL EARTH FAULT RELAY

To achieve discriminate clearance of high resistance earth faults, the distance
protection specified in Clause 14.4.1 shall be supplemented by an in-built
directional earth fault [DEF] function operating in conjunction with
teleprotection channels over multiplexed fibre optic links in a permissive
overreaching transfer trip of blocking mode selectable on site. At 220 kV, the
two DEF relays shall preferably be provided by different manufacturers.

The protection shall utilise different teleprotection channels to the distance
protection specified in Clause 14.4.1.

DEF relays shall be polarised by zero sequence voltage. The relay sensitivity
shall be adjustable between approximately 5 and 20% rated current. A relay
characteristic angle of 60 degrees is preferred but alternative angles will be
considered.

To prevent maloperation under current reversal conditions, during fault
clearance on the parallel circuit, the scheme shall include time delay relays or
other suitable means.

An adjustable time delay relay shall be provided to allow distance protection to
operate before the DEF relay for earth faults having values of arc resistance
which lie with the relay Zone 1 characteristic. A further time delay adjustable
from 0-10 seconds shall be provided to enable the relay to provide remote
back-up protection for high resistance faults independently of carrier
equipment. Auto reclosing shall be blocked in this case. It shall be possible to
selectively enable to disable the DEF Back-up function.

The DEF scheme in permissive mode shall include an "echo" feature to facilitate
tripping of the local circuit breaker if a line fault occurs when the remote end
disconnector is open or when the remote end DEF function has not started.
Suitable timers shall be included to prevent continuous carrier send when the
circuit breaker is open and to remove the "echo"


                                       87



signal after a timer, sufficient for tripping to occur, has elapsed. The echo
signal shall not be initiated by a single pole trip.

Selection facilities are required to either block or allow initiation of three
pole delayed auto reclose as desired.

14.5   220 kV AUTOMATIC RECLOSING

Three pole and/or single pole, single shot repetitive auto-reclosing equipment
shall be provided for 220 kV overhead line circuit breakers.

The scheme shall be specifically designed for substation layouts in which two
circuit breakers are associated with a single line end. Suitable logic shall be
included to enable the scheme to function as specified if one of the associated
circuit breakers is inoperable for any reason, and to prevent simultaneous three
pole reclosing of the circuit breakers.

Reclosure shall be initiated following tripping by the distance relay operating
in Zone 1 or in conjunction with teleprotection receive signal. Three pole
delayed auto-reclosing shall also be initiated by the directional earth fault
protection. Reclosure shall not be initiated in the event of a three phase
fault, nor any type of fault in the second or third back-up zones, nor when a
direct overtripping signal is received, nor when the circuit breaker is closed
onto a fault on a previously de-energized line. The following modes of operation
shall be selectable by means of a switch or switches:

(a) Single pole, high speed, auto-reclose. Auto-reclose shall be only initiated
in the event of a single phase to earth fault. All other types of faults shall
result in three phase tripping without auto-reclosing.

(b) Three pole delayed reclosing. Delayed reclosing shall only be initiated in
the event of a single phase or two phase fault. Three phase faults shall result
in tripping without auto-reclosing.

(c) Single pole, high speed and/or three phase delayed, auto-reclosing as
appropriate. Single pole, high speed auto-reclosing shall be initiated only in
the event of a single phase-earth fault and delayed reclosing initiated in the
event of a two phase fault. Three phase tripping without re-closing shall rake
place for three phase faults.

(d) No auto reclosing. Three phase tripping without auto-reclose shall take
place for any type of fault.

If a second earth fault occurs during the single pole auto-reclose dead time,
three phase tripping with subsequent delayed three pole auto-reclose shall take
place. If the auto-reclose selector switch is in the single pole reclose mode,
three phase tripping with lockout should follow.

The high speed and delayed reclosing dead times have to be co-ordinated with the
equipment being provided at the remote substation. Tentative ranges are as
follows:

High speed single pole reclose dead time - 0.3 to 3 seconds
Delayed three pole reclose dead time     - 3 to 30 seconds


                                       88



The reclaim time i.e. the time period following the automatic reclosing of the
circuit breaker, during which further faults result in three phase tripping and
lockout, shall be chosen to match the duty cycle of the circuit-breakers,
assuming the shortest available dead time is chosen. The reclaim time shall not,
however, be less than five seconds, and the reclaim time range shall extend to
180 seconds. (The reclaim time commences at the instant the reclose command is
given to the circuit breaker and, therefore, includes the circuit breaker
closing time).

The closing command shall be limited to two seconds, after which time the
reclosing equipment shall be automatically reset without resetting the reclaim
timer. The reclosing equipment shall also reset if dead line check or
synchronism check conditions are not satisfied within a predetermined time of
the check relays being energized.

A counter shall be provided to record the number of reclosures.

Reclosing schemes shall include voltage monitoring and check synchronising
relays as appropriate.

For dead line charging, voltage monitoring relays shall check the condition of
the line and busbar and permit three pole reclosing only when the line is
de-energised and the busbar is energised. The line is considered to be
de-energised when the voltage is less than twenty percent of rated voltage, and
the busbar is considered to be energised when the voltage is greater than eighty
percent of rated voltage.

(A signal shall be provided from the dead line check relays for interlocking of
the line earth switches to prevent the switches being closed onto a live line).

When a voltage is present on both sides of a circuit breaker, the synchronism
check relay shall monitor the magnitudes of the two voltages across the open
circuit breaker and the phase angle and slip frequency between these voltages.
Closing shall only be permitted when these are within prescribed limits.

Check synchronising relays shall comply with the requirements of Clause 14.2.
The same relays may be used as for manual closing.

14.6    BACK-UP OVERCURRENT

Inverse definite minimum time overcurrent and/or earth fault relays shall be
provided where specified. They shall be of Numeric type and shall have a
standard inverse characteristic according to IEC 60255.

Relays should have adjustable settings for both operating current and time, the
design of the relay being such that the setting adjustments can be carried out
on load without taking the relay out of service. The range of current settings
for phase faults shall be 50-200 per cent of rated current with tappings no
longer than 25 per cent intervals and the time multiplier setting shall be in
steps of 0.025.


                                       89



The relays shall be thermally rated such that the operating time of the relay at
the highest practical current levels on any combination of current and time
multiplier settings shall not exceed the thermal withstand time of the relay.

14.7    BREAKER FAILURE PROTECTION

Breaker failure protection shall be included for the 220 kV circuit breaker.

The breaker failure protection on a circuit breaker shall be initiated by all
the other protection devices which normally initiate tripping of that breaker.
In the event of the circuit breaker failing to open within a pre-selected time,
the breaker failure protection shall instigate tripping of all adjacent circuit
breakers. It shall also incorporate provision for initiating tripping of any
remote infeeds, via teleprotection channels over fibre optical communication
Links, as appropriate.

The position of each circuit breaker shall be monitored by two sets of current
relays fed from the back-up protection current transformers. The relay outputs
shall be connected in series in a "two out of two" arrangement. The relays shall
have an operating time of approximately 10 msecs, and a consistent rest time of
less than 15 msecs. The relays shall be capable of remaining in the operated
position continuously and carrying twice the circuit rated current continuously.

The operating time of the breaker failure protection shall be selected by means
of timers with ranges of 50 to 500 msecs. There shall be two timers per circuit
breaker. The timer tripping outputs shall be connected in a "two out of two"
arrangement and shall energise both tripping coils of the adjacent circuit
breakers. The timers shall be of static numeric design to minimise our travel.

The circuit Breaker Failure Protection Relay or Scheme employed shall be able to
employ both the Current Check and the Circuit Breaker Closed Status Criterion
for correct operation of the Circuit Breaker Failure Protection.

Initiation and Tripping of the Circuit Breaker Failure Protection shall be
interlocked with the Circuit Breaker busbar disconnectors and the 220 kV Power
Transformer Isolator. The Circuit Breaker Failure Protection Contacts for
Tripping and initiating Breaker failure schemes for adjacent as well as remote
Circuit Breakers shall be self reset. Circuit Breaker Lock-out Relays shall
however be electrically reset.

Incoming Breaker Failure Direct Inter-tripping commands from the remote
substation shall be interlocked with the status of the bay disconnector. The
D.T.T. command shall not trip the circuit breakers if the bay disconnector is in
open position.

14.8    DISTURBANCE RECORDER AND FAULT LOCATOR

The 220 kV feeder shall be monitored by a disturbance recorder to record
graphically the currents and voltages during fault conditions as well as the
operation of protective relays.

The following facilities should be provided:

[a]     Analogue channels to record voltages and currents.


                                       90



[b]     Digital channels to record chronologically relay operations.

[c]     Alarm contacts to indicate "disturbance recorder operating" and
        "disturbance recorder failure" in the Control Room.

[d]     Pushbutton to manually initiate recording of currents and voltages as
        well as the digital signals.

[e]     Memory for recording currents and voltages ten cycles prior to the
        occurrence of the fault.

[f]     Provision to adjust the recording period to cover a
        trip-autoreclose-trip cycle.

[g]     Device which records the precise time of the occurrence of the fault to
        the nearest milli-second.

The disturbance recorder shall be a numerical device and shall have adequate
memory to store a large number of events.

The memory capacity supplied shall equal what is generally available in the
market at the time of tender from leading manufacturers of disturbance
recorders.

FAULT LOCATION:

The disturbance reorder shall be a distance to Fault Location Facility. The
distance to fault shall be displayed in kilometres of line length on the
Disturbance Recorder LCD Display.

14.9    TRIPPING RELAYS

A Self reset Trip Relay shall be provided for each phase. This shall be of the
heavy duty type suitable for panel mounting.

A Lockout, Electrically reset Trip relay shall be provided for the line
protection.

Relay operating time shall not exceed 10 ms from initiation of trip relay
operating coil to contact close.

14.10   AUXILIARY VOLTAGE OPERATING RANGE

DC relays, coils, elements, etc. will be operated from a 110 V rated DC battery,
which under float charging conditions operates at 120 volts. DC operated relays,
coils, elements, etc. shall be suitable for operation over a voltage range of
121 to 88 volts i.e. 110V-20% +10%.

14.11   PROTECTION SETTINGS

Relay settings for all unit type protective schemes and for distance relay shall
be submitted to KPLC prior to commissioning of the Olkaria III substation and
Transmission Interconnector for approval. Settings shall also be provided for
those relays and other equipment provided under this Section of the Contract
which do not require an intimate knowledge of existing relay settings e.g.
circuit breaker fail relays. Details calculations shall be provided supporting
the recommended settings.

The back Overcurrent and Earth Fault Relays shall be set using Normal Inverse
Time-Current characteristics for IEC 60255 or BS 142. The Relay shall be set to
ensure coordination with other relays existing at Olkaria II substation.


                                       91



14.12   220 kV CONTROL PANEL

One panel shall be installed at Olkaria III Control room. The control panels
shall be equipped with the following equipments and devices:

A mimic of the Switchyard design incorporating the following:

Illuminating discrepancy control switches for circuit breaker and motorised
disconnector. Semaphore indicators for the hand operated disconnector and Line
Earth switch.

Override/On/Off key selector switch for the 220 kV Circuit Breaker.

Control selector switch for Supervisory/Remote control of circuit breaker and
motorised disconnector.

Multi-way alarm Annunciator Relay, complete with accept, reset and lamp
facilities. The Annunciator Relay shall provide for all alarms required for the
220 kV Line Protection.

Instruments for 220 kV Line
MW meter:
MV Ar meter:
Ammeter:
Voltmeter with selector switch.

14.13   PROTECTION RELAY PANELS

Three Protection panels shall be provided as follows:

Main 1 Protection
Main 2 Protection and Back-up Protection
Circuit Breaker Failure Protection and Autoreclose Relay. Trip Relays and Trip
Circuit Supervisory to be located in this panel.

110 V DC CHARGER AND BATTERIES

Duplicate sets (A & B) of 110 V DC Charger and batteries shall be provided and
installed in Olkaria III Control Room.

The Charger and Batteries shall be appropriately rated for the required
Protection and Control duties. Distribution Board with appropriate switchgear
shall be provided.

48 V DC CHARGER AND BATTERIES

Duplicate sets (A & B) of 48 V DC Charger and batteries shall be provided and
installed in Olkaria III Control Room.

The Charger and Batteries shall be appropriately rated for the required
communication duties. A distribution Board with appropriate switchgear shall be
provided.


                                       92



415 V AC AUXILIARY SUPPLY

415 V AC Distribution Board shall be provided at Olkaria III with adequate
outlets for the required applications

Two sources shall be connected to the Board through an Automatic Change-over
system.

Intentionally blank

14.14   OPGW, COMMUNICATION EQUIPMENT AND SCADA REQUIREMENTS

This section covers the Summary of Supply and Installation of communications,
telephones, tele-protection and SCADA equipment for the efficient supervision,
control, operation and maintenance of the transmission system.

COMMUNICATION SYSTEM

Optical fibre communication link is required from Olkaria III substation to
Olkaria II substation. At Olkaria II it shall be integrated by KPLC into the
existing communication System to Nairobi North and to the National Control
Centre.

The optical fibres shall be optical ground wire (OPGW) to be installed on the
220 kV Interconnector from Olkaria III to Existing Olkaria II Substation.

The system shall consist of 12-Fibre, dual window single mode fibre in
accordance with the ITU (T) recommendations OPGW over the transmission line
route.

SDH STM-1 optical terminal equipment

Communication equipment of Olkaria II end will be located in existing Olkaria II
substation control room.

SDH STM-1 multiplexing equipment providing protection. SCADA and voice
communications, including all necessary interface cards. This will provide for
new protection. SCADA and voice signals installed under this project as well as
any existing services which the client required to be carried on the optical
fibre.

Lead in cable at Olkaria III Substation connecting the PGW to the terminal
equipment.

DC power supplies by KPLC and OrPower 4 each at its side.

Spare fibres will be terminated in the building in such a way as to facilitate
their future use.

TERMINAL EQUIPMENT

The terminal equipment for the Fibre Optical Communication link shall be
installed at Olkaria III substation. This shall allow connection of Data for
SCADA, Speech and Teleprotection Signals to Olkaria II substation. This
equipment shall match the Interface Equipment at Olkaria II to allow integration
by KPLC into the existing communication system at Olkaria II and hence to
National Control Centre located at Juja Rd Substation in Nairobi, to provide
mounted in enclosed buildings at Olkaria III. No intermediate repeaters will be
used.


                                       93



LINE DIFFERENTIAL PROTECTION

This will use dedicated fibres.

SPEECH EQUIPMENT

A PABX exchange equipment already existing at Olkaria II. It's proposed to
connect two extensions from this exchange to Olkaria III substation through the
proposed communication link. However in case the equipment at Olkaria II
requires expansion to accommodate the additional telephone extension, this shall
be carried out by KPLC. Seller shall provide the telephone sets at Olkaria III.

REMOTE TERMINAL UNITS

A Remote Terminal Unit RTU shall be installed at Olkaria III Substation for
purposes of Supervisory or the Substation as well as the control of the
substation Equipment.

The Philosophy of Status, Alarms, Control and Measurements connected to SCADA
i.e. type and Numbers shall be followed, and mutually agreed by the parties.

The RTU shall be microprocessor bases and capable of handling all the facilities
at Olkaria III Power Station and Substation.

All status inputs whether events or alarms of at leas 20 milliseconds duration
must be captured and no power system data lost. The RTUs supplied must be
totally compatible, and capable of being integrated with the existing system.
The new RTU supplied under this contract shall support multiple protocols. As a
minimum requirements, they shall fully support the protocol used by the existing
SINDAC RTUs and also the IEC 870-5-101 protocol to enable them to be connected
to a different master station in the future.

The Seller shall state all the protocols supported by the RTU they propose to
install and the means by which the protocol used by the RTU can be changed at a
later date.

In the event of loss of dc to the RTU, internal battery back-up shall be
required to maintain any volatile memory for several hours. However for system
that require reloading of the RTU memory for whatever reason the procedure
should be simple without the need for sophisticated loading or test equipment.

For the purposes of RTU testing, self diagnosing facilities should be
incorporated and visual indication, by means of light emitting diodes (LEDs), of
fault conditions shall be required.

A SCADA interface Marshalling cubicle shall be supplied to interface all power
system data i.e. status indication alarms, analogues, interposing relays for
control outputs, etc. to the RTU. This cubicle shall also house transducers for
analogue inputs and interposing relays for control outputs.

48 volts DC power supplies shall be supplied to power the RTU, interposing
relays, telephones equipment.


                                       94



SCOPE OF WORK

The contractor shall include detailed system design, manufacture, supply,
installation, testing, commissioning, remedying of defects, maintaining the
works during the defects liability period and any incidental work necessary for
the proper completion of the work in accordance with this contract.

Detailed requirements are as follows:

System design - the system design and preparation of contractor's drawings to
approval of the Engineer

Supply and installation of fibre optic lead-in cables including mounting
hardware and splicing

Supply and installation of lead in cables to the equipment terminals.

Supply and installation of fibre optic terminal and multiplexing

Supply and installation of supervisory management system and cabling to the
relevant distribution frame(s)

Supply and installation of DC power supplies in Olkaria III only.

Factory testing of the terminal equipment and supervisory prior to delivery of
OrPower 4 supplied equipment.

Testing and commissioning of the systems up to the terminal equipment in Olkaria
II.

Multiplexed signals for permissive and direct inter-trips for the 220 kV
circuits.

CONTROL ROOM

A Control Room shall be constructed to house Protection and Control panels as
well as communications equipment and Auxiliary supply equipment belonging to
KPLC.

The Control Room shall have the following areas:

Protection Panels area
Communication equipment area
110 V & 48 V DC Charger area
110 V & 48 V DC Battery area

The designated areas shall be approximately sized to accommodate the respective
equipments.


                                       95



                           PART D: METERING EQUIPMENT

1.      METERING SYSTEM

(a)     KPLC shall, at its expense, procure and provide to the Seller the
        back-up metering equipment (the "Back-Up Metering Equipment") for the
        Early Generation Facility and the Plant, and the Seller shall install
        the same for KPLC and once the Seller has installed the system KPLC
        shall own and maintain it. The Seller shall, at its expense, procure,
        install, own and maintain the principal metering equipment (the "Main
        Metering Equipment") for the Early Generation Facility and the Plant.

(b)     KPLC shall provide and install a strip chart recorder and shall make a
        continuous recording of the Net Electrical Output and Reactive Power.
        Such Net Electrical Output and Reactive Power shall be recorded on
        appropriate magnetic media or equivalent, which recording shall be used
        to compute adjustments to the Capacity Payments as provided by Schedule
        5. Upon installation, such strip chart recorder shall constitute a part
        of the Metering System.

(c)     The metering points to record the MWh and Mvarh exchange between the
        Seller and KPLC shall be shown on Figures 3 and 4. The current and
        voltage transformers will measure current and voltage on the outgoing
        high voltage terminals of the step-up transformer of the Early
        Generation Facility and of the step-up transformers of the Plant. Where
        the Early Generation Facility does not have step up transformers then
        the current and voltage transformers will be located as close to the
        Interconnection Point as possible. The meters owned by KPLC will be
        located within the switchyard in a building housing all marshalling
        cubicles, control and metering panels and communication equipment. Any
        photographic facilities will be provided by the Seller as part of the
        verification process for monthly meter readings.

(d)     The Main Metering Equipment and the Back-Up Metering Equipment
        (collectively called the Metering System) shall be to a mutually agreed
        international standard providing a measured accuracy of +/- 0.2% for
        each individual component.

2.      INSTALLATION OF METERING SYSTEM

(a)     Subject to Section 2(b), the Seller shall, at its expense, install the
        Metering System on the Early Generation Site and the Site at locations
        to be agreed upon by the Parties, and upon completion convey to KPLC all
        right, title and interest in the Back-Up Metering Equipment free of all
        charges and encumbrances. Prior to the installation by the Seller of the
        Metering System, the Seller will deliver to KPLC the protection scheme
        and the metering plan of the Early Generation Facility and the Plant for
        KPLC's approval. KPLC will provide written comments on the protection
        scheme and the metering plan within thirty (30) days of their receipt.
        The Seller will incorporate KPLC's comments received during such thirty
        (30) day period into the protection scheme and the metering plan and
        deliver final copies to KPLC. KPLC will approve the final scheme and
        plan within fifteen (15) days or notify the Seller that it does not
        approve the scheme and plan, giving its reasons therefor. If KPLC does
        not give reasons for not approving the scheme and plan within such
        fifteen (15) day period, KPLC shall be deemed to have approved such
        scheme and plan. Upon


                                       96



        approval by KPLC, the Seller will complete the design and commence
        installation of the Metering System. Such installation shall be
        completed not later than fifteen (15) days prior to the scheduled date
        to begin initial testing of the Early Generation Facility or the Plant.
        The Seller shall provide KPLC with thirty (30) days advance notice of,
        and KPLC shall have the right to observe and inspect, the installation
        of the Metering System. KPLC shall be notified not less than fifteen
        (15) days prior to, and shall have the right to observe, the
        installation of the Back-up Metering Equipment by the Seller.

(b)     If the Back-up Metering Equipment is not provided to the Seller by KPLC,
        at a reasonable time taking into account the Construction Programme,
        then KPLC shall reimburse the Seller for all reasonable expenses
        incurred by the Seller for the acquisition of the Back-up Metering
        Equipment. Together with an invoice for reimbursement, the Seller shall
        provide reasonable documentation of the expenses incurred for the
        purchase of the Back-up Metering Equipment. Payment shall be due along
        with the first scheduled payment made pursuant to Clause 11.


                                       97



                             PART E: DELIVERY POINT

The Delivery Point for the Early Generation Facility is at the early generation
33 kV generating bus as shown on Figure 3.

The delivery point for the Plant is the OrPower side of the Line Disconnector
LD-3 as shown on Figure 4.


                                       98





                             PART F: RATED CAPACITY

The Rated Capacity of the Plant and of each Unit shall be:

              Capacity in MW (at reference conditions
              (see Note (1)), measured by the Metering System)   Comments
              ------------------------------------------------   --------
Plant                                48.0
Unit Number
Unit 1                                4.0                        Note (2)
Unit 2                                4.0                        Note (2)
Unit 3                                3.0                        Note (2)
Unit 4                              12.33
Unit 5                              12.33
Unit 6                              12.33


Notes:

     1.   Reference Conditions are specified in Part A of Schedule 2.

     2.   Already tested as part of the Early Generation Facility.


                                       99



                                    FIGURE 1

                             GENERAL MAP OF THE AREA

                                 (See Page ____)


                                       100



                                    FIGURE 2

                            MAP SHOWING LICENCE AREA

                                 (See Page ____)


                                       101



                                    FIGURE 3

                       EARLY GENERATION FACILITY DRAWINGS

                                 (See Page ____)


                                       102



                                    FIGURE 4

                                  PLANT DRAWING

                                 (See Page ____)


                                       103





SCHEDULE 3: MAINTENANCE ALLOWANCES OF THE EARLY GENERATION FACILITY AND THE
PLANT



     Early Generation Facility (at 12 MW)                     Plant (at 48 MW)
---------------------------------------------   ---------------------------------------------
Contract   Contracted      Annual Scheduled     Contract   Contracted     Annual Scheduled
  Year      Capacity    Maintenance Allowance     Year      Capacity    Maintenance Allowance
              (kW)           EGSMA (kWh)                      (kW)            SMA (kWh)
--------   ----------   ---------------------   --------   ----------   ---------------------

   1         12,000           2,016,000             1        48,000           8,410,000
   2         12,000           2,016,000             2        48,000           8,410,000
   3         12,000           2,016,000             3        48,000           8,410,000
   4         12,000           2,016,000             4        48,000           8,410,000
   5         12,000           2,016,000             5        48,000           8,410,000
   6         12,000           2,016,000             6        48,000           8,410,000
   7         12,000           2,016,000             7        48,000           8,410,000
   8         12,000           2,016,000             8        48,000           8,410,000
   9         12,000           2,016,000             9        48,000           8,410,000
   10        12,000           2,016,000            10        48,000           8,410,000
   11        12,000           2,016,000            11        48,000           8,410,000
   12        12,000           2,016,000            12        48,000           8,410,000
   13        12,000           2,016,000            13        48,000           8,410,000
   14        12,000           2,016,000            14        48,000           8,410,000
   15        12,000           2,016,000            15        48,000           8,410,000
   15        12,000           2,016,000            15        48,000           8,410,000
   17        12,000           2,016,000            17        48,000           8,410,000
   18        12,000           2,016,000            18        48,000           8,410,000
   19        12,000           2,016,000            19        48,000           8,410,000
   20        12,000           2,016,000            20        48,000           8,410,000



The Contracted Plant Capacity is the result of the Appraisal Works.

The Annual Scheduled Maintenance Allowance for the Early Generation Facility and
for the Plant, EGSMA and SMA, set forth in this Schedule shall be converted into
a Scheduled Maintenance Allowance for each month, EGSMA(p) and SMA(p), during
such Contract Year using the planned maintenance programme notified by the
Seller to KPLC in accordance with


                                       104



Clause 9.3 of this Agreement such that the total of monthly allowances for such
Contract Year will equal the Annual Scheduled Maintenance Allowance for such
Contract Year. The Scheduled Maintenance Allowance for each month shall be used
in the calculation of the Capacity Payment for such month in accordance with
Schedule 5. The Annual Outage Allowance for the Early Generation Facility (EGOA)
shall be set as zero point zero eight (0.08) or eight percent (8%), and the
Annual Outage Allowance for the Plant shall be set as zero point zero four
(0.04) or four percent (4%). This shall be used in the calculation of
Unscheduled Maintenance Allowance as set out in Schedule 5.

For the Early Generation the Contract Year 1 starts at the Early Generation
Commercial Operation Date and for the Plant the Contract Year 1 starts at the
Full Commercial Operation Date.


                                       105



                             SCHEDULE 4: PROCEDURES

                  PART A: COMMISSIONING AND TESTING PROCEDURES

1.      TESTS PRIOR TO SYNCHRONISATION OF EACH UNIT

Prior to the first synchronisation of each Unit and again after the installation
of the Early Generation Facility Units at the Plant Site, the Seller shall carry
out the following tests:

(a)     automatic voltage regulator setting and adjusting in stand-still
        condition and with the generator running at no load;

(b)     turbine governor control checks, including an overspeed test;

(c)     functional testing and timing of high voltage switchgear in the
        switchyard of the Early Generation Facility and the Plant; and

(d)     the Seller and KPLC shall verify that all protection level settings are
        as agreed, and shall complete injection tests to verify the operation of
        the protection relays, equipment and switchgear.

Where the Site and Temporary Site are at the same place and the Units of the
Early Generation Facility have not been disturbed during the installation of the
Plant then the Units of the Early Generation Facility shall not be required to
repeat the Unit Commercial Operations Tests.

2.      TESTS AFTER SYNCHRONISATION OF EACH UNIT AND UNIT COMMERCIAL OPERATIONS
        TESTS

(a)     After first synchronising each Unit, initial operational testing of each
        Unit shall be conducted by the Seller. Once the Seller is satisfied that
        each Unit is capable of continued reliable operation, the Seller shall
        so notify KPLC in accordance with Clause 7 of this Agreement and carry
        out the following tests (the "Unit Commercial Operations Tests"), which
        if the Unit satisfies the minimum performance criteria therefore, will
        result in the Unit having satisfied that test.

        (i)   Capacity Demonstration Test;

        (ii)  turbine governor operation;

        (iii) reactive capability;

        (iv)  minimum load capability;

        (v)   response of plant to step load changes.

(b)     Minimum performance criteria for the Unit Commercial Operations Tests
        are set out below.


                                      106



(i)      CAPACITY DEMONSTRATION TEST.

During the period of the Capacity Demonstration Test, the capacity of the Unit
will be demonstrated in the Demonstration Test, the capacity of the Unit will be
demonstrated in the following manner:

        o     the Unit shall be in operation at Rated Capacity with normal
              auxiliaries and Geothermal Reservoir load;

        o     the Seller will declare to KPLC the commencement of the test and
              will record the reading of the Metering System;

        o     the test duration will be six (6) hours and at the end of this
              period the Seller will record the new reading of the Metering
              System. The Capacity as determined by such test shall be the
              difference between the reading taken at the end of the sic (6)
              hour period and the reading taken at the beginning of such period,
              divided by six (6); provided, that the Capacity shall not be
              considered to have been established unless the result of such
              determination is equal to or greater than the minimum criteria for
              such test set forth below.

During Commissioning and the Operating Period the Capacity will be determined by
measuring the output at the outgoing busbars of the Unit through the Metering
System. Tests will be based on relevant American Society of Mechanical Engineers
standard ASME power test codes and IEC standards using plant instrumentation and
the Metering System. Test results shall be corrected to the "Reference
Conditions", specified in Schedule 2, Part A using the correction curves from
Figure 5 attached to this Schedule.

The Unit will have satisfied this test if it is demonstrated that the Capacity
of the Unit is greater than 70% of the Rated Capacity of each Unit at the date
of this Agreement provided that if at least 90% of Rated Capacity has not been
achieved within three (3) months of the date of the test, the Unit shall be
deemed to have failed the Capacity Demonstration Test and the Seller shall not
be entitled to receive any further Capacity Payments until the Unit achieves at
least 90% of the Rated Capacity at the date of this Agreement.

(ii)    TURBINE GOVERNOR OPERATION

The operation of each turbine will be demonstrated over the range of ninety five
percent (95%) to one hundred and five percent (105%) of rated speed.

(iii)   REACTIVE CAPACITY

Tests will demonstrate the capability of the Units to operate stably at rated
voltage and frequency at power factors and under reactive conditions as follows:

100% output   0.95 Leading Power Factor
100% output   0.85 Lagging Power Factor

The Unit shall meet the manufacturer's published curves at zero load.


                                      107



(iv)     MINIMUM LOAD TESTS

Each Unit shall prove its capability to operate stably at fifty percent (50%) of
the Capacity demonstrated in its Capacity Demonstration Test for a period of one
(1) hour with all other Units shut down and all normal auxiliaries in operation.

(v)     STEP LOAD CHANGE TESTS

Each Unit shall undergo a test which demonstrates in capability to change load
in steps of up to 10% of operating load. At the start of each test the Unit
shall be operated at approximately 50% of maximum output for a continuous period
of five (5) minutes. The load shall be increased to 55% in one step. The unit
shall have passed the test if it immediately responds to the change in load and
maintains 55% load for a further five (5) minutes.

3.      EARLY GENERATION FACILITY AND PLANT COMMERCIAL OPERATIONS TESTS

(a)     Following satisfactory completion of the Unit Commercial Operations
        Tests for all Units, the Seller shall carry out on the Early Generation
        Facility or the Plant the Early Generation Commercial Operations Tests
        or the Plant Commercial Operations Tests as the case may be. The Seller
        shall notify KPLC of its intention to carry out such tests in accordance
        with Clause 7 which, if the Early Generation Facility or the Plant as
        the case may be satisfies the minimum performance criteria thereof, will
        result in the Early Generation Facility or the Pant as the case may be
        having satisfied that test. These tests are:

        (i)   Contracted Capacity Test;

        (ii)  Reliability Run Test;

        (iii) Unit Trip Test;

        (iv)  Standby Supplies Test; and

        (v)   Environmental Tests.

(b)     The minimum performance criteria for the Early Generation Commercial
        Operations Tests or the Plant Commercial Operations Tests as the case
        may be are:

(i)     RELIABILITY RUN AND CONTRACTED CAPACITY

Upon completion of the Reliability Run Test prerequisites as included below the
Seller shall declare to KPLC the commencement of the Reliability Run Test.
During the period of the Reliability Run Test, the Contracted Capacity of the
Early Generation Facility or the Plant as the case may be will be determined in
the following manner:

        o     The Early Generation Facility or the Plant as the case may be
              shall be in operation in full output with normal auxiliaries and
              Geothermal Reservoir load;

        o     The Seller will declare to KPLC the commencement of the test and
              will record the reading of the Metering System;


                                      108



        o     The test duration will be six (6) hours and at the end of this
              period the Seller will record the new reading of the Metering
              System. The Capacity as determined by such test shall be the
              difference between the reading taken at the end of the six (6)
              hour period and the reading taken at the beginning of such period,
              divided by six (6); provided, that the Contracted Capacity shall
              not be considered to have been established unless the result of
              such determination is equal to or greater than the minimum
              criteria, corrected to "Reference Conditions" for such test as set
              forth below:

(ii)    CONTRACTED CAPACITY

During Commissioning and commercial operations the Contracted Early Generation
Capacity or Contracted Plant Capacity will be determined by measuring the output
at the Metering Point of the Early Generation Facility or the Plant as the case
may be through the Metering System. Tests will be based on relevant American
Society of Mechanical Engineers standard ASME power test codes and IEC standards
using plant instrumentation and the Metering System. Test results shall be
corrected to the "Reference Conditions" specified in Schedule 2, Part A using
the correction curves from Figure 5 attached to this Schedule.

In the event the Contracted Early Generation Capacity Test carried out during
Commissioning to enable the Early Generation Commercial Operation Date to occur
demonstrates that the Contracted Early Generation Capacity is greater than
ninety five percent (95%) but less than one hundred percent (100%) of the amount
shown as the Early Generation Facility Contracted Capacity at the date of this
Agreement then the Contracted Capacity shall be adjusted to such lesser amount.

In the event the Contracted Plant Capacity Test carried out during Commissioning
to enable the Full Commercial Operation Date to occur demonstrates that the
Contracted Plant Capacity is greater than seventy per cent (70%) but less than
one hundred percent (100%) of the amount agreed or determined by the Parties
pursuant to Clause 5, the Contracted Plant Capacity shall be adjusted to such
lesser amount provided that if at least 90% of Rated Capacity has not been
achieved within three (3) months of the date of the test, the Plant shall be
deemed to have failed the Contracted Plant Capacity Test and the Seller shall
not be entitled to receive any further Capacity Payments until the Plant
achieves at least 90% of the Rated Capacity agreed or determined pursuant to
Clause 5.

(iii)   RELIABILITY RUN

A reliability run for the Early Generation Facility or the Plant as the case may
be will be carried out as part of the Commissioning tests. The run will be for a
period of thirty (30) days and will include seventy-two (72) continuous hours at
one hundred percent (100%) base load (i.e. maximum continuous rating at the
prevailing ambient temperatures). The output during the remaining hours of the
test will be as requested by KPLC in accordance with Clause 8.3. The test shall
have been satisfactorily completed only if the Early Generation Facility or the
Plant as the case may be experiences no more than five events which prevent the
Early Generation Facility or the Plant as the case may be from delivering its
Contracted Capacity and no single event shall exceed five (5) hours. For the
purposes of this clause only a condition on KPLC's System which restricts
delivery of electrical energy from the Early Generation Facility or the Plant as
the case may be shall not be considered one of the five (5)


                                      109



allowable events. Test results shall be corrected to the "Reference Conditions",
specified in Schedule 2, Part A using the correction curves from Figure 5
attached to this Schedule.

(iv)    UNIT TRIP TEST

Tests shall demonstrate the ability of the Early Generation Facility or the
Plant as the case may be to withstand the simultaneous disconnection from the
KPLC System of the largest two (2) Units, operating at greater than ninety five
per cent (95%) of the capacity demonstrated in each Unit's Capacity
Demonstration Test, and to continue to operate in a safe manner. Each Unit shall
demonstrate that it is Capable of re-synchronisation within thirty (30) minutes.

(v)     STANDBY SUPPLIES TEST

With all Units shut down in either the Early Generation Facility or the Plant as
the case may be the Early Generation Facility or the Plant shall be disconnected
from the KPLC's System for six (6) hours.

The standby power supplies, as specified in paragraph 4.3(d) of Part A of
Schedule 2, shall maintain the Early Generation Facility in such a state
throughout the period of disconnection from the KPLC System that a binary energy
converter Unit can be synchronised within one (1) hour of reconnection to KPLC's
System. At the end of the disconnection period the Seller, with the agreement of
KPLC, shall re-synchronise the Early Generation Facility.

In the case of the Plant the standby power supplies, as specified in paragraph
4.3(d) of Part A of Schedule 2, shall maintain the Plant in such a state
throughout the period of disconnection from the KPLC System that a binary energy
converter Unit can be synchronised within one (1) hour of reconnection to KPLC's
System. At the end of the disconnection period the Seller, with the agreement of
KPLC, shall re-synchronise at least one )1) binary energy converter Unit and one
(1) steam turbine Unit.

(vi)    ENVIRONMENTAL TESTS

The Seller shall complete whatever tests are necessary to demonstrate compliance
with the Environmental Conditions as specified in paragraph 1.2 of Part A of
Schedule 2.


                                      110



                            PART B: METER PROCEDURES

1.      TESTING OF METERING SYSTEM

(a)     KPLC shall initially test the Metering System for accuracy in accordance
        with this Schedule 4 by the later of fifteen (15) days after it is
        installed by the Seller or five (5) days prior to the date scheduled for
        initial testing of the Early Generation Facility or the Plant as the
        case may be to begin, and thereafter at intervals of not less than one
        hundred and eighty (180) days after giving the Seller no less than
        forty-eight (48) hours advance notice. The Seller may have a
        representative present during any such testing, as well as during any
        inspection of the Metering System or adjustment thereof.

(b)     KPLC shall also test the Metering System at any other time reasonably
        requested by the Seller, such additional testing to be at the Seller's
        expense unless the test indicates that the Metering System is inaccurate
        by more than one-half percent (0.5%), in which case KPLC shall bear the
        cost of the additional test. The Seller may have a representative
        present during any such testing, as well as during any inspection of the
        Metering System or adjustment thereof.

(c)     When on the Site, KPLC shall comply with all reasonable instructions of
        the Seller and, notwithstanding any other provision in this Agreement to
        the contrary, shall indemnify and hold the Seller harmless from any loss
        or damage sustained by virtue of KPLC's negligence or wilful misconduct
        in the performance of its obligations but only to the extent that such
        loss or damage is not covered by insurance of the Seller.

(d)     The calibration of meters will be checked to ensure that the accuracy
        remains within the specified limits.

        The method of calibration and frequency of tests will be agreed between
        the Seller, and KPLC based on knowledge of the performance and the
        design of the installed meters and the manufacturers' recommendations.

(e)     Compensation will be made for the errors of current and voltage
        transformers in the meter calibration or during the computation of
        records. Current and voltage transformers will be tested for ratio and
        phase angle errors following manufacture at an accredited testing
        station in the presence of representatives from the Seller; and KPLC.
        Test certificates issued by the testing station will be issued
        independently to both parties.

(f)     Testing and calibration of the Metering System shall be carried out by
        KPLC after giving appropriate notice to the Seller, in line with the
        agreed frequency of testing or in the event of either Party having
        reasonable cause to believe the meters are outside specified limits.
        During such tests and calibration the Seller shall have the right to
        have a representative present at all times.


                                      111



2.      READING OF METERS

(a)     PROCEDURES: The Metering System shall be read monthly on the last
        business day of each month (or such other day as may be agreed upon by
        the Parties) for the purpose of determining the Net Electrical Output of
        the Early Generation Facility or the Plant as the case may be since the
        preceding reading. The Seller shall read the Metering System during the
        normal business hours and the Seller shall give KPLC at least
        forty-eight (48) hours notice of the time the Seller shall read the
        Metering System. In the event that a KPLC representative is present at
        such reading of the Metering System for the purpose of measuring Net
        Electrical Output, then such reading shall be jointly taken and
        recorded.

        Under normal circumstances the readings of the Main Metering Equipment
        shall be used to determine the amount of Net Electrical Output delivered
        by the Seller in any Period.

        In the event that a KPLC representative is not present at a reading of
        Net Electrical Output, then the Seller's representative shall take and
        record such reading and make a photographic record thereof. The Seller
        shall maintain a log of all such meter readings. Measurements recorded
        shall be delivered by the recording Party to the non-recording Party by
        facsimile within forty-eight (48) hours after the readings are taken. In
        the event that the Main Metering Equipment is not in service as a result
        of maintenance, repairs or testing, then the best available information,
        which may include the Back-Up Metering Equipment, shall be used during
        that period.

(b)     INACCURACIES IN METERING SYSTEM: When, as a result of any test of the
        Metering System, the Metering System is found to be inaccurate by more
        than one-half percent (0.5%) or is otherwise functioning improperly or
        if any seal securing the Metering System is found broken, then the
        correct amount of Net Electrical Output delivered to KPLC for the actual
        period during which inaccurate measurements were made, if any, shall be
        determined as follows:

(i)     First, the readings of the Back-up Metering Equipment, if any, shall be
        utilised to calculate the correct amount of Net Electrical Output,
        unless a test of such Back-up Metering Equipment, as required by either
        Party, reveals that the Back-up Metering Equipment is inaccurate by more
        than one-half percent (0.5%), is otherwise functioning improperly or any
        seal securing the Back-up Metering Equipment is found broken;

(ii)    If there is no Back-up Metering Equipment or if the Back-up Metering
        Equipment is found to be inaccurate by more than one-half percent
        (0.5%), is otherwise functioning improperly or any seal securing the
        Back-up Metering Equipment is found broken, then Seller and KPLC shall
        jointly prepare an estimate of the correct reading on the basis of all
        available information and such guidelines as may have been agreed to
        between the Seller and KPLC;

(iii)   In the event that KPLC and the Seller fail to agree upon an estimate for
        the correct reading, KPLC shall make any payments to the Seller required
        as a result of its estimate of the correct reading and the matter may be
        referred by either party for determination by an Expert pursuant to
        Clause 19; and


                                      112



(iv)    The difference between the previous payments by KPLC for the period of
        inaccuracy and the recalculated amount shall be offset against or added
        to the next payment to the Seller under this Agreement, as appropriate.
        If the period of inaccuracy cannot be accurately determined, it shall be
        deemed to have begun on the date which is midway between the date the
        meter was found to be inaccurate and the date of the last meter reading
        accepted by the Parties as accurate. In no event, however, shall any
        such adjustment be made for any period prior to the date on which the
        Metering System was last tested and found to be accurate within plus or
        minus one-half percent (0.5%) and not otherwise functioning improperly.


                                      113



                    PART C: OPERATING AND DESPATCH PROCEDURES

1.     SCHEDULING AND DESPATCH

(a)    In order to assist with scheduling of the Early Generation Facility to
       meet the requirements of KPLC, the Parties agree that the following
       procedures will be adhered to:

(i)    YEAR AHEAD NOTIFICATION: Not less than ninety (90) days before the Early
       Generation Commercial Operation Date, and thereafter not less than ninety
       (90) days before the beginning of each Operating Year, KPLC shall provide
       to the Seller estimated requirements on a monthly basis for Net
       Electrical Output for each subsequent Year, but KPLC shall not be bound
       by these figures.

(ii)   MONTH AHEAD NOTIFICATION: Not less than fourteen (14) days before the
       beginning of the Month prior to the Early Generation Commercial Operation
       Date and thereafter not less than fourteen (14) days before the beginning
       of each month, KPLC shall provide to the Seller estimated requirements,
       on a day-by-day basis, for Net Electrical Output during that Month and
       also, provisionally, for the following Month, but KPLC shall not be bound
       by these figures.

(iii)  WEEK AHEAD NOTIFICATION: Not less than forty-eight (48) hours before the
       beginning of the Week prior to the Early Generation Commercial Operation
       Date and thereafter not less than forty-eight (48) hours before the
       beginning of each week, KPLC shall provide to the Seller estimated
       requirements, on an hour-by-hour basis, for Net Electrical Output during
       that week and also, provisionally, during the following week, but KPLC
       shall not be bound by these figures.

(iv)   EARLY GENERATION FACILITY AVAILABILITY NOTIFICATION: To enable KPLC to
       give final schedules of requirements as required by subsection (v) below,
       the Seller shall, by 1200 hours the day before the Early Generation
       Commercial Operation Date and thereafter by 1200 hours each day, inform
       KPLC of the estimated Capacity Available during each hour of that day
       commencing thirty-six (36) hours ahead and, provisionally, for the day
       immediately thereafter. Such estimates shall not be binding upon the
       Seller, the Seller shall advise KPLC as soon as possible of any changes
       in its Declared Capacity for such days.

(v)    DAY AHEAD NOTIFICATION: Not less than seven (7) hours before the start of
       the day before the Early Generation Commercial Operation Date and
       thereafter not less than seven (7) hours before the start of each day,
       KPLC shall provide to the Seller firm requirements, on an hour by hour
       basis, for Net Electrical Output for the following day. The firm
       requirements shall not be binding upon KPLC and KPLC may subsequently
       alter its requirements.

       Actual operation levels requested of the Seller will be determined by the
       requirements for operation in accordance with economic despatch and may
       be substantially different from the information provided in accordance
       with this Part C; provided however, that actual operation levels
       requested by KPLC shall at all times be subject to compliance with the
       Operating Characteristics.


                                      114



(b)    In order to assist with scheduling of the Plant to meet the requirements
       of KPLC, the Parties agree that the following procedures will be adhered
       to:

(i)    YEAR AHEAD NOTIFICATION: Not less than ninety (90) days before the Full
       Commercial Operation Date, and thereafter not less than ninety (90) days
       before the beginning of each Operating Year, KPLC shall provide to the
       Seller estimated requirements on a monthly basis for Net Electrical
       Output for the remainder of the Operating Year in which the Full
       Commercial Operation Date is scheduled to occur, and thereafter for each
       subsequent Year, but KPLC shall not be bound by these figures.

(ii)   MONTH AHEAD NOTIFICATION: Not less than fourteen (14) days before the
       beginning of the Month prior to the Full Commercial Operation Date and
       thereafter not less than fourteen (14) days before the beginning of each
       month, KPLC shall provide to the Seller estimated requirements, on a
       day-by-day basis, for Net Electrical Output during that Month and also,
       provisionally, for the following Month, but KPLC shall not be bound by
       these figures.

(iii)  WEEK AHEAD NOTIFICATION: Not less than forty-eight (48) hours before the
       beginning of the Week prior to the Full Commercial Operation Date and
       thereafter not less than forty-eight (48) hours before the beginning of
       each week, KPLC shall provide to the Seller estimated requirements, on an
       hour-by-hour basis, for Net Electrical Output during that week and also,
       provisionally, during the following week, but KPLC shall not be bound by
       these figures.

(iv)   PLANT AVAILABILITY NOTIFICATION: To enable KPLC to give final schedules
       of requirements as required by subsection (v) below, the Seller shall, by
       1200 hours the day before the Full Commercial Operation Date and
       thereafter by 1200 hours each day, inform KPLC of the estimated Capacity
       Available during each hour of that day commencing thirty-six (36) hours
       ahead and, provisionally, for the day immediately thereafter. Such
       estimates shall not be binding upon the Seller, the Seller shall advise
       KPLC as soon as possible of any changes in its Declared Capacity for such
       days.

(v)    DAY AHEAD NOTIFICATION: Not less than seven (7) hours before the start of
       the day before the Full Commercial Operation Date and thereafter not less
       than seven (7) hours before the start of each day, KPLC shall provide to
       the Seller firm requirements, on an hour by hour basis, for Net
       Electrical Output for the following day. The firm requirements shall not
       be binding upon KPLC and KPLC may subsequently alter its requirements.

       Actual operation levels requested of the Seller will be determined by the
       requirements for operation in accordance with economic despatch and may
       be substantially different from the information provided in accordance
       with this Part C; provided however, that actual operation levels
       requested by KPLC shall at all times be subject to compliance with the
       Operating Characteristics.

(c)    NOTICE OF CHANGE OF OPERATING LEVELS: In connection with its rights to
       Despatch the Early Generation Facility or the Plant as the case may be in
       accordance with this Agreement, KPLC will provide the Seller with at
       least five (5) minutes advance notice of changes in operating levels to
       be achieved by the Early Generation Facility


                                      115



       or the Plant as the case may be (or such greater period as may be
       required by the Operating Characteristics.

(d)    Where the Early Generation Facility or the Plant as the case may be
       suffers an Availability Failure the Seller shall notify KPLC of the
       Capacity available and this shall be the Declared Capacity as soon as
       practicable. When the Availability Failure has been cleared the Seller
       shall notify KPLC of the increased Declared Capacity as soon as
       practicable. KPLC shall always use the Declared Capacity as notified
       under this section as the upper limit for Despatch Instructions.

(e)    Dispatched partial load will be no less than fifty per cent (50%) of Unit
       Capacity. There will be no more than [2] shut downs despatched per month.

2.     OPERATION IN ACCORDANCE WITH DESPATCH

       Early Generation Facility or the Plant as the case may be shall be
       operated by the Seller in accordance with the Despatch Instructions
       within a despatch tolerance band of +3%.

3.     RECORDING OF TELEPHONED COMMUNICATIONS

       Each Party hereby authorises the other Party to record all telephoned
       voice communications relating to Declared Capacity control and Despatch
       of the Early Generation Facility or the Plant as the case may be received
       from the other Party pursuant to this Agreement and shall supply, at the
       request of the other Party, a copy or transcript of any such recording.


                                      116



                                    FIGURE 5

                                CORRECTION CURVE

                                   (See Page ___)


                                      117



                               SCHEDULE 5: PAYMENT

                         PART A: EARLY GENERATION TARIFF

The total levels of tariff payments in respect of the Early Generation Facility
in each month shall be according to the following:

(i)    Prior to the Early Generation Commercial Operation Date the total tariff
       payments in any month shall be equal to EGEC(p); and

(ii)   Following the Early Generation Commercial Operation Date but prior to the
       Early Generation Cessation Date the total tariff payments in any month
       shall be equal to EGEC(p) plus EGCP(p).

Where EGEC(p) and EGCP(p) are calculated in accordance with Part A of this
Schedule.

                                 ENERGY CHARGES

1.     CALCULATION OF ENERGY CHARGES

For the purposes of Clause 10.2, KPLC shall pay to the Seller Energy Charges in
respect of the Net Electrical Output of the Early Generation Facility in each
month calculated as follows:



       EGEC(p) = EGNEO(p) x EGECR(p)

where:

EGEC(p)    =   the aggregate amount of Energy Charges (US$) payable in respect
               of month p;

EGNEO(p)   =   the aggregate Net Electrical Output (kWh) of the Early Generation
               Facility in month p; and

EGECR(p)   =   the Energy Charges Rate (expressed in US$/kWh) prevailing in
               month p as calculated in Paragraph 2 directly below.



                                      118



2.     ENERGY CHARGE RATE

The Energy Charges Rate for the Early Generation Facility during each month
shall be calculated as follows:

                             CPI(p-1)


       EGECR(p) = EGECR(b) x --------
                              CPI(b)

where:

EGECR(p)   =  as previously defined;

EGECR(b)   =  zero point zero one five six US Dollars per kWh (0.0156US$/kWh)
               the Base Energy Charge Rate

CPI(p-1)   =  The United States Consumer Price Index for the month 3 months
               prior to the month p; and

CPI(b)     =  the United States Consumer Price Index for June 1996


The royalty charge, currently set at 0.004US$/kWh, will be added to the Energy
Charge Rate at cost.

                                CAPACITY PAYMENTS

1.     CAPACITY CHARGE RATE

The Capacity Charge Rate for the Early Generation Facility during each month
shall be calculated as follows:

EGCCR(p) = E + F

where:

EGCCR = the Capacity Charge Rate for month p, (expressed in US$/kW/month)

      U      Z
E =  --- x  ---  (the non-escalable component of the Capacity Charge Rate)
      12    100

where:

U = five hundred and two point nine US Dollars per kW per year
    (502.9 US$/kW/year); and

Z = fifty per cent (50%) the percentage of U represented by the fixed
    Capacity Charge Rate


                                      119



     -         -
    |  U     G  |   CPI(p-1)
F = | --- x --- | x -------- (the escalable component of the Capacity
    |  12   100 |    CPI(b)  Charge Rate)


     -         -

where:

G          =  the percentage of U represented by escalable costs such that
              G = 100%-Z;

CPI(p-1)   =  as previously defined; and

CPI(b)     =  as previously defined


2.     PASS THROUGH COST - Not Applicable

3.     CALCULATION OF CAPACITY PAYMENTS

The Seller shall be entitled to Capacity Payments in respect of Capacity of the
Early Generation Facility in each month calculated as follows:



EGCP(p) = EGCCR(p) x EGCC

Where:

EGCP(p)    =  the Capacity Payments for the month p (expressed in US$)

EGCCR(p)   =  as previously defined; and

EGCC       =  the Contracted Early Generation Capacity (expressed in kW)


4.     MONTHLY AVAILABILITIES

For each month in each Operating Year, starting with the month in which the
Early Generation Commercial Operation Date occurs, there shall be calculated a
Monthly Target Availability and an Actual Monthly Availability as follows:


                                      120





(i)    MONTHLY TARGET AVAILABILITY

EGMTA(p) = (EGCC x H(p)) - EGSMA(p) - EGUSMA(p)

where

EGMTA(p)    =   the Monthly Target Availability (expressed in kWh);

EGCC        =   as previously defined;

H(p)        =   the hours in month p;

EGSMA(p)    =   the Scheduled Maintenance Allowance in month p (expressed in
                kWh) representing the total energy not available for delivery in
                month p due to scheduled maintenance outages computed assuming
                the Early Generation Capacity would otherwise have been
                dispatched at its Contracted Capacity calculated using the
                values of EGSMA set forth in Schedule 3; and

EGUSMA(p)   =   the Unscheduled Maintenance allowance in month p (expressed in
                kWh) as calculated using the following formula:

                                         ((EGD x M))
            (EGCC x EGD x H(y) x EGOA) -   [SIGMA]  EGSMA(p)
                                            (p=1)
EGUSMA(p) = -----------------------------------------------
                            EGD x M(y)

where:

EGD    =   the duration in years between the Early Generation Commercial
           Operation Date and the planned date of the Early Generation Cessation
           Date;

H(y)   =   the number of hours in a year being eight thousand seven hundred and
           sixty (8760);

M(y)   =   the number of months in a year being twelve (12); and

EGOA   =   Annual Outage Allowance - as described in Schedule 3.


Where the Early Generation Facility continues to operate after the Early
Generation Cessation Date then this section shall be recalculated using the
revised planned date of the Early Generation Cessation Date.

(II)   ACTUAL MONTHLY AVAILABILITY

The Actual Monthly Availability of the Early Generation Facility in month p,
EGAMA(p), (expressed in kWh) shall be calculated using the following formula:

           (2 x H(p))  AC(y)
EGAMA(p) =   [SIGMA]  (-----)
              (y=1)      2

where:

AC(y) =  the Early Generation Available Capacity in Settlement Period y
         (expressed in kW)


                                      121



5.     ADJUSTMENT OF CAPACITY PAYMENTS FOR MONTHLY AVAILABILITY - FIRST MONTH OF
       OPERATING YEAR

If in the first month of an Operating Year, starting with the month in which the
Early Generation Commercial Operation Date occurs, the Actual Monthly
Availability is less than the Monthly Target Availability, the Capacity Payment
for that month shall be multiplied by the factor:

EGAMA(p)
--------
EGMTA(p)

6.     ADJUSTMENT OF CAPACITY PAYMENTS FOR MONTHLY AVAILABILITY - SUBSEQUENT
       MONTHS OF OPERATING YEAR

If in any subsequent month m of an Operating Year, the sum of the individual
Actual Monthly Availabilities for the year to date is less than the sum of the
individual Monthly Target Availabilities for the year to date, then the Capacity
Payment for that month shall be adjusted such that:

              (m)              EGAMA(p)
EGACP(tp) = [SIGMA] (EGCP(p) x --------)
             (p=1)             EGMTA(p)

where:

EGACP(tp) = the total of the Actual Capacity Payments received in the Operating
            Year for each month up to and including month m.

If in any subsequent month m of an Operating Year, the sum of the individual
Actual Monthly Availabilities for the year to date is greater than or equal to
the sum of the individual Monthly Target Availabilities for the year to date,
then the Capacity Payment for that month shall be adjusted, if such an
adjustment is required, such that:

              (m)
EGACP(tp) = [SIGMA] (EGCP(p))
             (p=1)

7.     FORCE MAJEURE PAYMENTS

For any month in which all or part of the Capacity of the Early Generation
Facility is unavailable as a result of Force Majeure the Seller shall be
entitled to Capacity Payments [which shall be calculated as follows, and
prorated for the number of hours in the month for which the Force Majeure
exists:



EGLC x E


                                      122



where:

EGLC   =   the Capacity not Available as a result of the event of Force Majeure
           (expressed in kW); and

E      =   90% of the Capacity Charge Rate as defined in paragraph 1 above
           (expressed in US$/kW/month).


The payment under paragraph 2 shall be reduced by an amount equal to the
Capacity Payment the Seller would have received had the Force Majeure event not
occurred. For the purposes of this paragraph "Force Majeure" shall not include
events or circumstances specified in Clauses 15.1(ii), (iii) and (iv) save that
in respect of Clause 15(iii) this paragraph shall apply if epidemics or plagues
materially affect the operation of the Early Generation Facility.

8.     CHANGES IN CONTRACTED CAPACITY

In the event that the Contracted Capacity for the Early Generation Facility is
altered under the provisions of this Agreement during any month, the calculation
of payments shall be adjusted pro rata to reflect the differing proportions of
the month for which differing Contracted Capacities were agreed.


                                      123



                              PART B: PLANT TARIFF

The total levels of tariff payments in respect of the Plant in each month shall
be according to the following:

(i)    Following the Early Generation Cessation Date but prior to the Full
       Commercial Operation Date the total tariff payments in any month shall be
       equal to MEC(p); and

(ii)   Following the Full Commercial Operation Date for the remainder of the
       Term the total tariff payments in any month shall be equal to MEC(p) plus
       CP(p).

Where MEC(p) and CP(p) are calculated in accordance with Part B of this
Schedule.

                                 ENERGY CHARGES

1.     CALCULATION OF ENERGY CHARGES

For the purposes of Clause 10.2, KPLC shall pay to the Seller Energy Charges in
respect of the Net Electrical Output of the Plant in each month calculated as
follows:



MEC(p) = NEO(p) x ECR(p)

where:

MEC(p)   =   the aggregate amount of Energy Charges (US$) payable in respect of
             month p;

NEO(p)   =   the aggregate Net Electrical Output (kWh) of the plant in month p;
             and

ECR(p)   =   the Energy Charge Rate (expressed in US$/kWh) in month p as
             calculated in accordance with Paragraph 2 directly below.




2.     ENERGY CHARGE RATE

The Energy Charge Rate, ECR(p), for the Plant in month p shall be calculated as
follows:

                  CPI(p-1)
ECR(p) = ECR(b) x --------
                   CPI(b)

where:

ECR(b)     =   zero point zero one nine two four US Dollars per kWh (0.01924
               US$/kWh) the Base Energy Charge Rate;

CPI(p-1)   =   as previously defined; and

CPI(b)     =   the United States Consumer Price Index for March 2005 = 193.30


The royalty charge, currently set at 0.004US$/kWh, will be added to the Energy
Charge Rate at cost.


                                      124



                                CAPACITY PAYMENTS

1.     CAPACITY CHARGE RATE

1.1    The Capacity Charge Rate for the Plant during each month consists of the
       following two components:

(i)    CCRE(p) with respect to 25% portion (CCE) of the Contracted Capacity; and

(ii)   CCRF(p) with respect to the remaining portion (CCF) of the Contracted
       Capacity.

CCE and CCF shall be calculated as follows:

CCE = CC x 0.25

CCF = CC-CCE

where:

CC = the Contracted Capacity (expressed in kW).

1.2    CCRE(p) and CCRF(p) during each month shall be calculated as follows:

1.2.1    Calculation of CCRE(p)

CCRE(p) = AE + BE - R(p)

where:

CCRE(p) = the Capacity Charge Rate for CCE for month p,
          (expressed in US$/kW/month)



     VE    C
AE = -- x --- (the non-escalable component of the Capacity Charge Rate)
     12   100

VE      =   VE(1) for the period commencing on the Full Commercial Operation
            Date and ending on the eleventh (11th) anniversary of the Full
            Commercial Operation Date;

                                       or

        =   VE(2) for the period after the eleventh (11th) anniversary of the
            Full Commercial Operation Date.

where:

VE(1)   =   five hundred sixty one point six three six US Dollars per kW per
            year (561.636 US$/kW/year) the CCE Base Capacity Charge Rate;

VE(2)   =   12 x (CCRE(p) + R(p)) of the month in which the eleventh (11th)
            anniversary of the Full Commercial Operation Date occurs; and



                                      125





C       =   the percentage of VE represented by the fixed Capacity Charge Rate,
            which shall be fifty per cent (50%) until the day which is the
            eleventh (11th) anniversary of the Full Commercial Operation Date,
            and which shall be seventy-five per cent (75%) thereafter; and

      -        -

     | VE    DE |   CPI(p-1)
BE = | -- x --- | x -------- (the escalable component of the Capacity
     | 12   100 |    CPI(b)  Charge Rate)


      -        -

where:

DE         =   the percentage of VE represented by the escalable costs such as
               fixed O&M costs, insurance and administrative costs, DE = 100% -
               C;

CPI(p-1)   =   as previously defined;

CPI(b)     =   CPI(b1) for the period commencing on the Full Commercial
               Operation Date and ending on the eleventh (11th) anniversary of
               the Full Commercial Operation Date;

                                       or

           =   CPI(b2) for the period after the eleventh (11th ) anniversary of
               the Full Commercial Operation Date.

where:

CPI(b1)    =   the United States Consumer Price Index for March 2005 = 193.30;
               and

CPI(b2)    =   CPI(p-1) of the month in which the eleventh (11th) anniversary of
               the Full Commercial Operation Date occurs.


           CPI(p-1)
R(p) = R x -------  (the reduction in the Capacity Charge Rate for month p,
           CPI(b3)  expressed in US$/kW/month)



where:

R          =   RY/12

RY         =   twenty-five US Dollars and fifty US cents per kW per year (25.50
               US$/kW/year)

CPI(b3)    =   the United States Consumer Price Index for July 2003 = 183.9

CPI(p-1)   =   as previously defined.


1.2.2  Calculation of CCRF(p)



CCRF(p) = AF + BF

where:

CCRF(p)   =   the Capacity Charge Rate for CCF for month p,
              (expressed US$/kW/month



                                      126





     VF    C
AF = -- x ---   (the non-escalable component of the Capacity Charge Rate)
     12   100

VF   =   VF(1) for the period commencing on the Full Commercial Operation Date
         and ending on the eleventh (11th) anniversary of the Full Commercial
         Operation Date;

                                       or

     =   VF(2) for the period after the eleventh (11th) anniversary of the Full
         Commercial Operation Date.

where:

VF(1)   =   four hundred eight-five US Dollars per kW per year (485 US$/kW/year)
            the CCF Base Capacity Charge Rate; and

VF(2)   =   12 x CCRF(p) of the month in which the eleventh (11th) anniversary
            of the Full Commercial Operation Date occurs; and

C       =   as previously defined; and

      -         -

     |  VF   DF  |   CPI(p-1)
BF = |  -- x --  | x -------- (the escalable component of the Capacity Charge
     |  12   100 |   CPI(b)    Rate)


      -         -

where:

DF         =   the percentage of VF represented by escalable costs such as fixed
               O&M costs, insurance and administrative costs, DF = 100% - C

CPI(p-1)   =   as previously defined;

CPI(b)     =   CPI(b1) for the period commencing on the Full Commercial
               Operation Date and ending on the eleventh (11th) anniversary of
               the Full Commercial Operation Date;

                                       or

           =   CPI(b2) for the period after the eleventh (11th) anniversary of
               the Full Commercial Operation Date.

where:

CPI(b1)    =   the United States Consumer Price Index for March 2005 = 193.30;
               and

CPI(b2)    =   CPI(p-1) of the month in which the eleventh (11th) anniversary of
               the Full Commercial Operation Date occurs.


2.      PASS THROUGH COST

This subsection 2 is for the KPLC's internal purposes only, and shall not affect
the calculation of Capacity Payments payable to OrPower 4.


                                      127



The Capacity Charge Rate for the Plant during each month calculated in
accordance with this Part B of Schedule 5 shall include a pass through component
to consumers being a fuel displacement cost as follows:

(i)     With respect to 25% portion (CCE) of the Contracted Capacity as
        specified in this Part B of Schedule 5:

        CCRE(pt1)   =   325.749 US$kW/yr (58% of the base Capacity Charge Rate
                        of 561.636 US$/kW/yr)

(ii)    With respect to the remaining portion (CCF) of the Contracted Capacity:

        CCRE(pt2)   =   281.3 US$/kW/yr (58% of the base Capacity Charge Rate of


                        485 US$/kW/yr)

where:

CCRE(pt1)   =   pass through component of CCRE(p)

CCRE(pt2)   =   pass through component of CCRF(p)


3.      CALCULATION OF CAPACITY PAYMENTS

The Seller shall be entitled to Capacity Payments in respect of Capacity in each
month calculated as follows:



CP(p) = CCRE(p) x CCE + CCRF(p) x CCF

where:

CP(p)     =   the Capacity Payment for month p (expressed US$);

CCRE(p)   =   the Capacity Charge Rate for CCE for month p (expressed in
              US$/kW/month)

CCRF(p)   =   the Capacity Charge Rate for CCF for month p (expressed in
              US$/kW/month

CCE       =   the portion of the Contracted Capacity as previously defined
              (expressed in kW)

CCF       =   the portion of Contracted Capacity as previously defined
              (expressed in kW)


4.      MONTHLY AVAILABILITIES

For each month in each Operating Year, starting with the month in which the Full
Commercial Operation Date occurs, there shall be calculated a Monthly Target
Availability and an Actual Monthly Availability as follows:


                                      128





(i)     MONTHLY TARGET AVAILABILITY

MTA(p) = (CC x H(p)) - SMA(p) - USMA(p)

where:

MTA(p)   =   the Monthly Target Availability (expressed in kWh);

CC       =   as previously defined;

H(p)     =   as previously defined;

SMA(p)   =   the Scheduled Maintenance Allowance in month p (expressed in kWh)
             representing the total energy not available for delivery in month p
             due to scheduled maintenance outages computed assuming the Plant
             would otherwise have been dispatched at its Contracted Capacity;
             and

USMA(p)  =  the Unscheduled Maintenance allowance in month p (expressed in kWh)
            shall be calculated using the following formula:

                                        (PPA(t)) x M(y)
          (CC x PPA(t) x H(y) x (OA)) - [SIGMA] SMA(p)
                                        (p=1)



USMA(p) = --------------------------------------------
                          (PPA(t) x M(y))

where:

PPA(t)   =   the number of years between the Full Commercial Date and the end of
             end of the Term;

H(y)     =   as previously defined;

M(y)     =   as previously defined; and

OA       =   The Annual Outage Allowance - as set forth in Schedule 3.


Where the Contracted Capacity of the Plant changes after the Full Commercial
Operation Date then USMAp shall be recalculated from the date of the change in
the Contracted Capacity. PPA1 shall be the number of years between the date of
the Contracted Capacity change and the end of the end of the Term which does not
have to be an integer, CC shall be the revised Contracted Capacity in kW and all
other parameters shall be those as in the initial calculation.



(ii)    ACTUAL MONTHLY AVAILABILITY

         2 x H(p)  AC(y)
AMA(p) = [SIGMA] (------)
          (y=1)      2


                                      129



where:

AMA(p)   =   the Actual Monthly Availability of the Plant in the month p
             (expressed in kWh)

AC(y)    =   as previously defined


5.      ADJUSTMENT OF CAPACITY PAYMENTS FOR MONTHLY AVAILABILITY - FIRST MONTH
        OF OPERATING YEAR

If in the first month of an Operating Year, starting with the month in which the
Full Commercial Operation Date occurs, the Actual Monthly Availability is less
than the Monthly Target Availability, the Capacity Payment for that month shall
be multiplied by the factor:

AMA(p)
------
MTA(p)

6.      ADJUSTMENT OF CAPACITY PAYMENTS FOR MONTHLY AVAILABILITY - SUBSEQUENT
        MONTHS OF OPERATING YEAR

If in any subsequent month m of an Operating Year, the sum of the individual
Actual Monthly Availabilities for the year to date is less than the sum of the
Individual Monthly Target Availabilities for the year to date, then the Capacity
Payment for that month shall be adjusted such that

            (m)            AMA(p)
ACP(tp) = [SIGMA] (CP(p) x ------)
           (p=1)           MTA(p)



where:

ACP(tp)   =   the total of the Actual Capacity Payments received in the
              Operating Year for each month up to and including month m.


If in any subsequent month m of an Operating Year, the sum of the individual
Actual Monthly Availabilities for the year to date is greater than or equal to
the sum of the individual Monthly Target Availabilities for the year to date,
then the Capacity Payment for that month shall be adjusted, if such an
adjustment is required, such that:

          (m)
ACP(tp) = [SIGMA] CP(p)
           (p=1)

7.      FORCE MAJEURE PAYMENTS

For any month in which all or part of the Capacity of the Plant is unavailable
as a result of Force Majeure the Seller shall be entitled to Capacity Payments
which shall be calculated as follows, and pro rated for the number of hours in
the month for which the Force Majeure exists:


                                       130





LC x A

where:

LC   =   the Capacity not Available as a result of the event of Force Majeure;
         (expressed in kW); and

A    =   90% of the Capacity Charge Rate as defined in paragraph 1 above
         (expressed in US$/kW/month)


The payment under paragraph 2 shall be reduced by an amount equal to the
Capacity Payment the Seller would have received had the Force Majeure event not
occurred. For the purposes of this paragraph "Force Majeure" shall not include
events or circumstances specified in Clauses 15.1(ii), (iii) and (iv) save that
in respect of Clause 15.1(iii) this paragraph shall apply if epidemics or
plagues materially affect the operation of the Plant.

8.      CHANGES IN CONTRACTED CAPACITY

In the event that the Contracted Capacity is altered under the provisions of
this Agreement during any month, the calculation of payments shall be adjusted
pro rata to reflect the differing proportions of the month for which differing
Contracted Capacities were agreed.


                                      131



                                PART C: INVOICING

1.      Content: The invoice shall, subject to this Part C, be in such form as
the Seller shall from time to time reasonably determine, and shall:

(a) have a unique number by which the invoice may be identified; and

(b) identify the month in respect of which payment is due; and

(c) state the Energy Charge for the month in respect of which payment is due,
including the relevant quantities metered and recorded in accordance with Clause
11 and Part B of Schedule 4 and such other information including relevant value
of the United States Consumer Price Index and calculations, in reasonable
detail, to permit KPLC to confirm the consistency of the invoice with the
provisions of Schedule 5; and

(d) state the Capacity Charge Rate for the month in respect of which payment is
due and such other information including the relevant value of the United States
Consumer Price Index and calculations, in reasonable detail, to permit KPLC to
confirm consistency of the invoice with provisions of Schedule 5; and

(e) state the Monthly Target Availability and the Actual Monthly Availability
for that month; and

(f) state any other charge payable by KPLC together with such other information
and calculations, in reasonable detail, as shall be required by KPLC to verify
that charge; and

(g) state the total amount payable; and

(h) state the due date for payment of the invoice.

2. Compliance with statutes, etc.: Each invoice shall comply with all relevant
statutes, regulations and directives, including those relating to Value Added
Tax.

3. Details: Each invoice shall be accompanied by a detailed statement setting
out the Declared Capacity in respect of each Settlement Period, revisions (if
any) to the Contracted Capacity following a Contracted Capacity Test, details of
any Availability Failure and the computation of the Net Electrical Output
delivered at the Delivery Point in response to a Despatch Instruction for each
Settlement Period and such other information and calculations, in reasonable
detail, as shall be required by KPLC to verify the invoice.


                                       132



                          PART D: CONSUMER PRICES INDEX

1. If in the opinion of either Party the CPI cannot be properly calculated as a
result of any of the following circumstances (an "Event"):

(a) the non-availability or discontinuance of one or more of the figures, values
or prices required to calculate the CPI (whether permanent or temporary);

(b) an error is contained in one or more of the published figures, values or
prices required to calculate the CPI;

(c) the basis upon which the CPI is calculated has been changed and thereby
superseded so as materially to affect the validity of CPI comparison over time
other than any change arising from changes in the respective consumption
patterns upon which the CPI was based;

then the Parties shall meet and seek in good faith to agree upon the means
whereby the CPI may be adjusted or to agree upon a replacement index and if the
Parties cannot agree upon such adjustment or replacement index within a period
of thirty (30) days either Party may refer the matter to an Expert who shall
determine such replacement index as most closely reflects the CPI prior to the
Event and also the date from which such replacement index shall be applicable.

2. If an index other than the CPI shall be used, then the provisions of this
Part D of this Schedule 4 shall apply to such index mutatis mutandis.


                                       133



                        SCHEDULE 6: CONDITIONS PRECEDENT

                       Part A: Preconditions of the Seller

(i) The grant to the Seller of geothermal resources licence for the Licence Area
necessary for the Geothermal Reservoir Development;

(ii) The execution by the GOK of the Site Agreement;

(iii) The granting to the Seller of a Water Permit.

                          Part B: Preconditions of KPLC

(i) The Seller providing to KPLC such documentary evidence as shall reasonably
satisfy KPLC that the Seller has or has access to such funds as are necessary
for the conduct of the Appraisal Works and construction of the Early Generation
Facility in accordance with the terms of this Agreement. Such documentary
evidence shall include evidence of all loans, grants or other financing
arrangements as the Seller shall have procured.


                                       134



                       SCHEDULE 7: CONSTRUCTION PROGRAMME

                                 (See Page ____)


                                       135



                SCHEDULE 8: PARTIES' ADDRESSES AND NOTICE DETAILS

KPLC:

The Kenya Power & Lighting Company Ltd.
Stima Plaza
P.O. Box 30099-00100
Nairobi, 243366
Kenya

Fax: 30099

Tel: 32013201

Marked for the attention of: The Company Secretary

Seller:

OrPower 4 Inc.
6225 Neil Road Suite 300
Reno
Nevada 89511-1136
USA

Fax: Nevada, USA (775) 356-9039

Tel: Nevada, USA (775) 356-9029

with copy to:

OrPower 4
Kenya Branch
Off Moi South Lake Road
Hellsgate National Park
P.O. Box 1566
20117, Naivasha, Kenya

In either case marked for the attention of: the Company President


                                       136



                              SCHEDULE 9: INSURANCE

                           Part A: Construction Period

  (The period from the Effective Date until the Full Commercial Operation Date)

1.   Marine and Air Cargo:

Cover: All materials, equipment, machinery, spares and other items for
incorporation in the Plant and the Seller's Steam Field Facilities against all
risks of physical loss or damage while in transit by sea or air from country of
origin anywhere in the world to the Site in Kenya, or vice versa from time of
the insured items leaving warehouse or factory for shipment to the Site. Cover
to institute Cargo Clauses (Air), institute War Clauses (Air), (Sendings By
Post), institute Strikes Clause (Cargo, Air Cargo) or equivalent.

Sum Insured: An amount equal to cost and freight of any shipment

Deductible: Not to exceed US$ 10,000 for each loss; except US$ 5,000 for the
turbine/generators.

Insured: The Seller and its relevant contractors.

2.   Loss of Revenue Profits (following Marine incident) - "Marine Delay in Full
     Commercial Operation Date"

Cover: Against loss of revenue following delay in start of commercial operations
as a direct result of physical loss or damage to the materials, equipment,
machinery and other items in transit by sea or air to the Site, to the extent
covered under the Marine Cargo insurance.

Sum Insured: An amount equal to the estimated continuing expenses, including
debt service, during the indemnity period.

Indemnity Period: 12 months or the period required to repair or replace
materials, equipment or machinery, whichever is less.

Deductible: Not to exceed 60 days.

Insured: The Seller.

3.   Contractors' All Risks

Cover: The contract works including the Early Generation Facility, Appraisal
Works executed and in the course of execution, materials and temporary works,
while on the Site, against all risks of physical loss or damage other than war
and kindred risks, nuclear risks, unexplained shortage, cost of replacing or
repairing items which are defective in workmanship material or design;
penalties; consequential losses; cash; vehicles; vessels; aircraft and other
standard exclusions contained in such policies. Cover shall provide the
equivalent terms, conditions and perils/causes of loss provided under the
Erection All Risks insurance policy.


                                       137



Sum Insured: The Contract Price.

Deductibles: In relation to Contract Works, Materials, etc.

(a)  arising during the construction and testing period:

(i) from Storm, Tempest, Flood, Water Damage, Earthquake, Subsidence and
Collapse - Not to exceed [US$ 10,000]

(ii) from any other cause other than in (a)(i) above - Not to exceed [US$ 5,000]

(b)  arising out of operational testing or Commissioning:

(i) of turbine generators - Not to exceed US$ 50,000

(ii) of plant other than turbine generators - Not to exceed US$ 35,000

Period of Cover: Actual construction, testing and Commissioning.

Insured: The Seller, its contractors and its lenders and all suppliers on the
Site; KPLC shall be added as an additional insured as its interests may appear.

4.   Loss of Revenue (following C.A.R.) "Delay in a Commercial Operation Date"

Cover: Against loss of revenue following delay in start of commercial operations
as a direct result of physical loss or damage to the works during construction
or operational testing to the extent that such loss or damage is covered under
the Contractors' All Risks policy.

Sum Insured: An amount equal to the estimated continuing expenses, including
debt service, during the indemnity period.

Indemnity Period: Not less than 12 months.

Insured: the Seller and its lenders.

Deductible: Not more than 90 days.

Period of Cover: Construction, testing and Commissioning periods of the Early
Generation Facility and Plant from mobilization of the Seller's contractors
until the day following the Full Commercial Operation Date.

5.   Public Liability

Cover: Against legal liability to third parties for bodily injury or damage to
property arising out of the construction, testing and Commissioning of the Early
Generation Facility and the Plant.

Sum Insured: For any one claim: US$ 5,000,000.


                                       138



Deductible: Not to exceed US$ 25,000 for each claim for damage to property. None
for injury to persons.

Insured: The Seller and its contractors; KPLC shall be added as an additional
insured as its interest may appear.

Period of Cover: The actual construction, testing and Commissioning of the Early
Generation Facility and the Plant from mobilization of the Seller's contractors
until the day following Full Commercial Operation Date.

6.   Miscellaneous

Other insurance as is customary, desirable or necessary to comply with local or
other requirements, such as Workmen Compensation Insurance in relation to all
workmen employed in the construction of the Plant and Motor Insurance on a
vehicle.


                                       139




                            Part B: Operating Period

 (The period from the Full Commercial Operation Date until the end of the Term)

1.   All Risks Insurance - Fixed Assets

Cover: All building contents, machinery, stock, fixtures, fittings and other
personal property forming part of the Plant against "All Risks" of physical loss
or damage, including (but not limited to) those resulting from fire, lightning,
explosion, spontaneous combustion, storm, wind, tempest, flood, hurricane, water
damage, riot, strikes, malicious damage, earthquake, collapse and/or loss of
contents of tanks, subject to standard policy exclusions.

Sum Insured: Full replacement value of the Plant.

Deductible: Not to exceed US$ 50,000 each loss.

Insured: The Seller and its lenders; KPLC shall be added, as an additional
insured as its interests may appear.

2.   Consequential Loss Following All Risks

Cover: Loss of revenue due to loss of capacity and/or loss of output as a direct
consequence of loss of or damage to Plant and caused by a period insured under
paragraph 1 above.

Sum Insured: An amount equal to the estimated continuing expenses, including
debt service, during the indemnity period.

Indemnity Period: Not less than 12 months.

Deductible: Not more than 60 days.

Insured: The Seller and its lenders.

3.   Machinery Breakdown

Cover: All machinery, plant and ancillary equipment forming part of the Plant
against sudden and unforeseen physical loss or damage resulting from mechanical
and electrical breakdown or derangement, explosion or collapse of pressure
vessels, electrical short circuits, vibration, misalignment, excessive current
or voltage, abnormal stresses, centrifugal forces, failure of protective or
regulating devices, overheating, entry of foreign bodied, impact, collision and
other similar causes.

Sum Insured: Full replacement value of all machinery, plant, boilers, etc.

Deductible: US$ 10,000 each loss.

Insured: The Seller and its lenders; KPLC shall be added as an additional
insured as its interest may appear.


                                       140



4.   Consequential Loss following Machinery Breakdown

Cover: Loss of revenue due to loss of capacity and/or loss of output as a direct
consequence of loss or damage to the Plant caused by a peril insured under
paragraph 3 above.

Sum Insured: an amount equal to the estimated continuing expenses, including
debt service, during the indemnity period.

Indemnity Period: Not less than 12 months.

Deductible: Not more than 60 days.

Insured: The Seller and its lenders.

5.   Public Liability

Cover: Legal liability of the insured for damage to property of third parties or
bodily injury to third parties arising out of the ownership, operation and
maintenance of the Plant.

Sum Insured: US$ 5,000,000 for any occurrence.

Deductible: US$ 25,000 each claim for property. None for injury to persons.

Insured: The Seller and its lenders; KPLC shall be added as an additional
insured as its interest may appear.

6.   Off Site Facilities

The Seller shall ensure that all plant, equipment and machinery which is
necessary for the operation or development of the Early Generation Facility or
the Plant but which is not located at the Temporary Site or the Site as the case
may be which shall include but not be limited to: drilling rigs and equipment,
wells, pipework, cables and instrumentation equipment is comprehensively insured
to its replacement values. The Seller shall also procure loss of revenue and
third party insurance to a suitable value to be agreed with KPLC for this plant
equipment and machinery.

7.   Miscellaneous

Other insurance as are customary, desirable or necessary to comply with local or
other requirements, such as Workmen's Compensation insurance in relation to all
workmen employed in the Plant or in connection with its operation, and Motor
Insurance on any vehicle.

If KPLC is added as an additional insured on any of the insurance listed in this
Schedule 9, KPLC acknowledges and agrees that (a) it will not be included as a
loss payee on any insurance proceed payments relative to such insurance
coverage, and (b) it will not be involved in any claim negotiations, discussion
or settlements.


                                       141



                                   SCHEDULE 10

                                 SITE AGREEMENT

                                 (See Pages __)


                                      142



                             DATED JANUARY 19, 2007

                    (1)  THE KENYA POWER AND LIGHTING COMPANY LIMITED

                    (2)  ORPOWER 4 INC.

                                   ----------

                     OLKARIA III PROJECT SECURITY AGREEMENT

                                   ----------


















                                                                               1


                                    CONTENTS

CLAUSE        HEADING                                                       PAGE
1.   AMENDMENT AND RESTATEMENT, DEFINITIONS AND INTERPRETATION.................0
2.   LETTER OF CREDIT..........................................................4
3.   GENERAL...................................................................5
4.   REPRESENTATIONS, WARRANTIES AND COVENANTS.................................6
5.   INDEMNITY.................................................................7
6.   CONFIDENTIALITY...........................................................7
7.   AMENDMENTS................................................................7
8.   MISCELLANEOUS.............................................................7
9.   COMMUNICATIONS............................................................8
10.  GOVERNING LAW AND DISPUTE RESOLUTION......................................9
11.  COUNTERPARTS.............................................................11
     SCHEDULE 1: FORM OF LETTER OF CREDIT.....................................12
     SCHEDULE 2: FORM OF COMFORT LETTER.......................................15
     SCHEDULE 3: FORM OF L/C BANK INSTRUCTION.................................16














                                                                               2


                     OLKARIA III PROJECT SECURITY AGREEMENT

THIS AGREEMENT is dated January 19, 2007.

BETWEEN:

(1)  THE KENYA POWER AND LIGHTING COMPANY LIMITED a company incorporated in
     Kenya with its registered office at Stima Plaza, PO Box 30099-00100,
     Nairobi, Kenya ("KPLC")

(2)  ORPOWER 4 INC. a company incorporated in the Cayman Islands, British West
     Indies with its registered office in Grand Cayman, British West Indies,
     with an office at 6225 Neil Road, Suite 300, Reno, Nevada, U.S.A. and which
     will act through its branch at Off Moi South Lake Road, Hellsgate National
     Park, P.O. Box 1566- 20117, Naivasha, Kenya ("ORPOWER 4")

WHEREAS:

     (A)  KPLC and OrPower 4 have entered into the PPA (as defined below).

     (B)  Pursuant to Clause 11.9.1 of the PPA, KPLC has agreed to provide
          security for all sums payable by KPLC under Clause 11 of the PPA.

     (C)  KPLC and OrPower 4 entered into the Security Agreement dated 5th
          November, 1998, and subsequently entered into the Amended and Restated
          Security dated 17th April 2003, which amended and restated the
          original Security Agreement. The Amended and Restated Security
          Agreement was not operationalized. KPLC and OrPower 4 wish to replace
          these prior arrangements regarding securities, all as described
          herein.

     (D)  This Olkaria III Project Security Agreement is entered into as of the
          date first appearing above, and supercedes the original Security
          Agreement dated 5th November, 1998 and the Amended and Restated
          Security Agreement of dated 17th April 2003 between the Parties
          hereto.

WITNESSETH as follows:

1.   AMENDMENT AND RESTATEMENT, DEFINITIONS AND INTERPRETATION

1.1  With effect from the Effective Date, the original Security Agreement dated
     5th November 1998 and the Amended and Restated Security Agreement dated 17
     April



                                                              Security Agreement

     2003 between the Parties, inclusive of all schedules thereto, shall be
     amended and restated in their entirety by this Olkaria III Project Security
     Agreement.

1.2  In this Agreement and its recitals hereto, unless the context otherwise
     requires, expressions and terms not otherwise defined herein shall have the
     meanings given to them in the PPA.

1.3  In this Agreement the following words and expressions have the following
     meanings:

     "APPROVED BANK": a first class international bank or financial institution
     nominated by KPLC and acceptable to OrPower 4, which, at the Effective
     Date, is any of Standard Chartered Bank (Kenya) Ltd, Barclays Bank of Kenya
     Limited or Citibank N.A. (and in each case their respective successors in
     title) and which, at a later date shall include the above named banks (or
     their respective successors in title, according to the case) on condition
     that there is no material adverse change in the value of such bank (or the
     value of its successor in title from that existing with respect to its
     predecessor) as of the Effective Date, and any other bank or financial
     institution which is reasonably acceptable to OrPower 4;

     "BUSINESS DAY": any day (other than a Saturday or Sunday) on which banks
     are open for business in Kenya;

     "DOLLARS" and "$": the lawful currency for the time being of the Untied
     States of America;

     "EFFECTIVE DATE": means the date first appearing above;

     "GOOD FAITH DISPUTE PROCEDURE": shall be as defined in the PPA;

     "INSOLVENCY EVENT": any of the following events or, in any other
     jurisdiction, any event similar or analogous to any of the following:

     (a)  a resolution being passed, or a petition being presented or any
          proceeding being commenced for the winding up, liquidation,
          administration, rehabilitation, rescue or dissolution of OrPower 4, or
          if OrPower 4 is or becomes the subject of any of those procedures,
          which petition or proceeding is not discharged or cancelled or
          otherwise reversed within 14 days; or

     (b)  OrPower being or becoming unable to pay its debts or suspending or
          threatening to suspend making payment with respect to all or any class
          of its debts;

     "KENYA SHILLINGS": means the lawful currency for the time being of Kenya;

     "L/C BANK": an Approved Bank;


                                       1



                                                              Security Agreement

     "L/C BANK LETTER OF INSTRUCTION": a letter in the form set out in Schedule
     3 (form of L/C Bank Letter of Instruction) or such other form as OrPower 4,
     KPLC and the L/C Bank may agree;

     "LETTER OF CREDIT": an irrevocable and transferable standby letter of
     credit issued or to be issued to OrPower 4 pursuant to Clause 2.1 and
     substantially in the form set out in Schedule 1 (Form of Letter of Credit)
     or, if the L/C Bank does not agree to issue a standby letter of credit in
     that form in such other form as KPLC, OrPower 4 and the L/C Bank may
     reasonably agree, and the expression includes each successive letter of
     credit issued pursuant to Clauses 2.2 and 2.3;

     "MONTH": a calendar month;

     "PARTY" and "PARTIES": each party or (as the case may be) the parties to
     this Agreement;

     "PAYMENT DEFAULT" means that KPLC shall have failed to make any payment in
     respect of the Secured Liabilities and:

     (a)  OrPower 4 has given to KPLC notice of that failure (by personal
          delivery or by facsimile transmission in accordance with Clause 9),
          specifying in that notice the amount of that non-payment and two (2)
          Business Days (or where such payment was required to be made to a
          payee outside the Republic of Kenya, five (5) Business Days) have
          elapsed since the giving of that notice; and

     (b)  either there is no dispute regarding the amount which KPLC has failed
          to pay, or, if there is such a dispute, such dispute is not being
          resolved according to the Good Faith Dispute Procedure;

     "PPA": the Amended and Restated Power Purchase Agreement entered into
     between OrPower 4 and KPLC of even date hereof;

     "PROJECT": the conduct of the Appraisal Works, the design, construction and
     operation of the Early Generation Facility and the Plant and the sale to
     KPLC of electricity generated by and capacity made available by the Early
     Generation Facility and the Plant;

          "RESERVED AMOUNT": means an amount equal to RA in the following
     formula:

          RA = CP + 0.96 * EC

     where:

          (a)  in respect of the first three Letters of Credit to be issued
               under this Agreement:

               CP = CCRF(P) * 36 MW; and


                                       2



                                                              Security Agreement

               EC = ECR(P) * 36 MW * 8760; and
                                     ----
                                      12

          (b)  in respect of the fourth and each subsequent Letter of Credit to
               be issued under this Agreement:

               CP = [SIGMA] (CCRF(P) * CCF)(R-12);
                            ---------------
                               12

               EC = [SIGMA] (ECR(P) * CCF)(R-12) *  8760;
                                                   -----
                                                   12*12

               (or, in respect of the fourth such Letter of Credit, if at the
               relevant time fewer than twelve (12) months have elapsed since
               the Full Commercial Operation Date, such amounts to be calculated
               pro rata)

     and where:

     CCRF(P), ECR(P) and CCF shall have the meanings given to those items in
     Schedule 5 of the PPA;

     R is the month in which the Reserved Amount is calculated; and

     [SIGMA](expression)(R-12) means the sum of that expression for the 12
     months prior to month R; and

     "SECURED LIABILITIES": all present and future obligations and liabilities
     of KPLC to pay sums on or after the Plant Commissioning Date to OrPower 4
     under Clause 11 of the PPA.

1.4  References to Clauses and Schedules are to the clauses and schedules of or
     to this Agreement.

1.5  Clause headings are inserted for ease of reference only and are not to
     affect the interpretation of this Agreement.

1.6  Except to the extent the context otherwise requires, any reference in this
     document to this "Agreement" shall include this Agreement as amended,
     varied, supplemented, novated or replaced from time to time.

1.7  References to any person are to be construed to include references to that
     person's successors, transferees and assigns.

1.8  Words denoting the singular number only shall include the plural number
     also and vice versa, and words denoting natural persons shall be
     interpreted as referring to corporations and any other legal entities and
     vice versa.


                                       3



                                                              Security Agreement

1.9  All references to time shall be to Kenya time.

1.10 The term including shall be construed without limitation.

1.11 In the event of any conflict between the Clauses and the Schedules, the
     Clauses shall prevail.

2.   LETTER OF CREDIT

2.1  KPLC shall, within 30 days of execution of this Olkaria III Project
     Security Agreement, procure that the L/C Bank establishes and maintains in
     favour of OrPower 4 a Letter of Credit in an amount not less than four (4)
     times the Reserved Amount as anticipated by the Parties as at the Full
     Commercial Operation Date.

     On the Effective Date, KPLC and OrPower 4 shall jointly instruct the L/C
     Bank in accordance with the terms of the L/C Bank Letter of Instruction.

2.2  KPLC shall ensure that the Letter of Credit shall have an expiry date not
     less than twelve (12) months from the date of its issue and shall ensure
     that successive Letters of Credit shall thereafter be issued (subject to
     Clause 2.7 and notwithstanding the provisions of Clause 2.4) for successive
     periods of twelve (12) months each, each such Letter of Credit to be in an
     amount not less than four times the Reserved Amount from time to time
     agreed or determined under Clause 2.3. OrPower 4 and KPLC shall not
     unreasonably withhold their agreement to the form of the first or any
     successive Letter of Credit if the L/C Bank will not issue such Letter of
     Credit substantially in the form set out in Schedule 1.

2.3  Within five (5) Business Days of the Effective Date with respect to the
     first Letter of Credit, and not less than sixty-five (65) days prior to the
     expiry date of the first Letter of Credit and of each subsequent Letter of
     Credit, OrPower 4 will notify KPLC, with a copy to the L/C Bank, of the
     relevant Reserved Amount to be used to calculate the amount of the next
     succeeding Letter of Credit, such notice to be accompanied by its
     calculations showing how that amount has been calculated. KPLC will have
     five (5) Business Days to advise OrPower 4 whether or not it agrees with
     OrPower 4's figure. If KPLC does not agree with that figure, and that
     figure is not agreed between OrPower 4 and KPLC within a further period of
     ten (10) Business Days, KPLC may refer the matter to an Expert for
     determination in accordance with Clause 19.3 of the PPA. If KPLC does not
     refer the matter to an Expert in accordance with this Clause 2.3, OrPower
     4's figure shall apply.

2.4  Subject to Clause 2.7, the L/C Bank shall be irrevocably instructed by KPLC
     and by OrPower 4 that, if by the second Business Day prior to the expiry
     date of any Letter of Credit, KPLC has not caused the renewal of the Letter
     of Credit, then the L/C Bank shall automatically renew the Letter of Credit
     by drawing down the balance of the Letter of Credit immediately prior to
     its expiry. The L/C Bank shall issue such new Letter of Credit upon the
     expiration of the existing Letter of Credit.


                                       4



                                                              Security Agreement

2.5  On and after the occurrence of a Payment Default which is continuing, and
     without prejudice to any other rights or remedies which OrPower 4 may have
     against KPLC, OrPower 4 shall be entitled to make demand under the Letter
     of Credit for an amount no greater than the amount of the Secured
     Liabilities then due but unpaid. Any such demand shall be in writing and
     signed by a duly authorised representative of OrPower 4. OrPower 4 shall
     provide a copy of the demand to KPLC (by personal delivery or by facsimile
     transmission in accordance with Clause 9) contemporaneously with delivery
     of the demand to the L/C Bank.

2.6  Until such time as the Secured Liabilities are paid or satisfied in full,
     KPLC shall use all reasonable endeavours to reinstate any Letter of Credit
     in respect of which a demand has been made pursuant to Clause 2.10 within
     thirty (30) days after that demand is made and shall in any event reinstate
     such Letter of Credit within ninety (90) days after such demand.

2.7  KPLC shall not be obliged to ensure the issue of a new Letter of Credit in
     accordance with Clause 2.2 on or at any time after the twelfth (12th)
     anniversary of the Full Commercial Operation Date.

2.8  All costs, charges, expenses, taxes and fees relating to the establishment
     and maintenance of the Letter of Credit shall be borne and paid by KPLC,
     provided however, that OrPower 4 shall reimburse KPLC for such costs,
     charges, expenses, taxes and fees paid up to the total aggregate amount of
     1% (one percentage) per annum of the then prevailing face value of the
     Letter of Credit issued in favour of OrPower 4 in accordance with this
     Clause 2. OrPower 4 shall reimburse amounts payable to KPLC pursuant to
     this Clause 2.8 quarterly in arrears, within 30 days of KPLC's invoice
     documenting such costs at the end of the quarter, up to the aforesaid cap.

2.9  Orpower 4 undertakes not to make a demand under the Letter of Credit before
     the Plant Commissioning Date.

2.10 There are no conditions precedent to the effectivity of this Olkaria III
     Project Security Agreement.

3.   GENERAL

3.1  This Agreement shall continue in force until the day immediately preceding
     the twelfth (12th) anniversary of the Full Commercial Operation Date.

3.2  The security constituted by this Agreement shall be continuing security,
     shall extend to the ultimate balance of the Secured Liabilities and shall
     continue in full force and effect notwithstanding any intermediate payment
     in whole or in part of the Secured Liabilities.

3.3  KPLC's liability under this Agreement shall not be discharged or impaired
     by:


                                       5



                                                              Security Agreement

     (a)  the dealing with, existence or validity of any other guarantee or
          security taken by OrPower 4 in relation to the PPA or the Secured
          Liabilities or any enforcement of or failure to take, perfect or
          enforce any such security;

     (b)  any amendment to or variation of the PPA or any security relating to
          the PPA or the Secured Liabilities;

     (c)  any release of or granting of time or any other indulgence to KPLC or
          any third party; or

     (d)  any other act, event or omission which would or might but for this
          Clause 3.3 operate to impair or discharge the security constituted by,
          or KPLC's liability under, this Clause including any act, omission or
          thing which would or might afford a defence to a surety.

4.   REPRESENTATIONS, WARRANTIES AND COVENANTS

4.1  Each Party represents, warrants and undertakes to the other that:

     (a)  this Agreement does not and will not conflict with or result in any
          breach or constitute a default under any agreement, instrument or
          obligation to which that Party is a party or by which it is bound;

     (b)  all necessary authorisations and consents to enable or entitle that
          Party to enter into this Agreement and which are material in the
          context of this Agreement have been obtained and will remain in full
          force and effect during the term of this Agreement;

     (c)  that Party shall obtain, effect and maintain all governmental
          licences, authorisations, consents, registrations, filings or
          approvals which are at any time necessary to enable it to comply with
          and/or perform its obligations under this Agreement;

4.2  OrPower 4 undertakes:

     (a)  that it will give prompt notice to KPLC of any Insolvency Event; and

     (b)  immediately upon termination of this Agreement or (if earlier) of the
          PPA, each other than due to a KPLC default relating to the Secured
          Liabilities, to:

          (i) give notice to that effect to the L/C Bank; and

          (ii) request and instruct the L/C Bank to cancel immediately the
     Letter of Credit, and to do all acts and things, and sign, seal, execute,
     deliver and perfect all deeds,


                                       6



                                                              Security Agreement

     instruments, notices and documents which the L/C Bank reasonably considers
     to be necessary or desirable in order to effect the cancellation.

5.   INDEMNITY

     OrPower 4 irrevocably and unconditionally agrees to indemnify KPLC and keep
     it indemnified against all losses, damages, costs, expenses, demands and
     claims (including interest, penalties, legal and other costs and expenses
     and any taxes thereon, if applicable) incurred or to be incurred by KPLC
     and arising out of all or any of:

     (a)  the making of any demand under the Letter of Credit otherwise than
          strictly in accordance with this Agreement; and

     (b)  the failure by OrPower 4 to give any such notice, instruction or
          request as is referred to in Clause 4.2(a) or (b)(i).

     For the avoidance of doubt, in no case shall OrPower 4 be liable to KPLC
     for any indirect or consequential losses or damages.

6.   CONFIDENTIALITY

     The provisions of Clause 18 of the PPA shall be incorporated mutatis
     mutandis in this Agreement. The provisions of this Clause 6 shall survive
     the termination or expiry of this Agreement.

7.   AMENDMENTS

     This Agreement shall not be amended except by an instrument executed by all
     the Parties.

8.   MISCELLANEOUS

8.1  No delay or omission on the part of any Party in exercising any right or
     remedy under this Agreement shall impair that right or remedy or operate as
     or be taken to be a waiver of it nor shall any single partial or defective
     exercise of any such right or remedy preclude any other or further exercise
     under this Agreement of that or any other right or remedy.

8.2  The rights of the Parties under this Agreement are cumulative and not
     exclusive of any rights provided by law and may be exercised from time to
     time and as often as the Parties deem expedient.

8.3  Any waiver by either Party of any terms of this Agreement or any consent or
     approval given by either Party under it shall only be effective if given in
     writing and then only for the purpose and upon the terms and conditions, if
     any, on which it is given and if agreed to by the other Party.


                                       7



                                                              Security Agreement

8.4  If at any time any one or more of the provisions of this Agreement is or
     becomes illegal, invalid or unenforceable in any respect under any law of
     any jurisdiction neither the legality, validity or enforceability of the
     remaining provisions of this Agreement nor the legality, validity or
     enforceability of such provision under the law of any other jurisdiction
     shall be in any way affected or impaired as a result.

8.5  This Agreement may not be assigned by either Party without the consent in
     writing of the other Party provided that:

     (a)  OrPower 4 may transfer, assign or novate this Agreement to any
          provider to it of finance for the purposes of the Project; and

     (b)  this Agreement may be assigned by either Party with the prior written
          consent of the other Party and the provisions of Clause 21.2 of the
          PPA shall apply to this Agreement.

8.6  Waiver of Sovereign Immunity

     KPLC agrees that the execution, delivery and performance by it of this
     Agreement and the obligation to open and maintain Letters of Credit
     hereunder, constitute private and commercial acts. In furtherance of the
     foregoing, KPLC agrees that:

     (a)  should any proceedings be brought against KPLC or its assets in any
          jurisdiction in connection with this Agreement, or in connection with
          any of KPLC's obligations or any of the transactions contemplated by
          this Agreement, no claim of immunity from such proceeding will be
          claimed by or on behalf of itself or any of its assets;

     (b)  it waives any right of immunity which KPLC or any of its assets has or
          may have in the future in any jurisdiction in connection with any such
          proceedings.

9.   COMMUNICATIONS

9.1  Any notice or other communication to be given by one Party to the other
     under or in connection with this Agreement shall be given in writing and
     may be delivered personally or sent by prepaid airmail or facsimile to the
     recipient in accordance with the details set out below or to such other
     address and/or facsimile number and/or person as the Parties may notify
     each other in accordance with this Clause for such purpose:

     OrPower 4
     Postal address:


                                       8



                                                              Security Agreement

     6225 Neil Road Suite 300
     Reno
     Nevada 89511-1136
     USA

     Fax Number: Nevada, USA (775) 356-9039
     Telephone Number: Nevada, USA (775) 356-9029
     with a copy to:

     OrPower 4
     Off Moi South Lake Road,
     Hellsgate National Park
     P.O. Box 1566- 20117
     Naivasha Kenya

     Fax Number: +254-50-50668
     Telephone Number: +254-50-50664 or +254-50-50663

     In either case marked for the attention of: The Company President

     KPLC
     Postal Address:
     The Kenya Power and Lighting Company Limited
     Stima Plaza
     PO Box 30099-00100
     Nairobi
     Kenya

     Fax Number: Nairobi, 337351
     Telephone Number: Nairobi 243366

     Marked for the attention of: The Company Secretary.

9.2  Every notice or other communication shall be deemed to have been received
     (if sent by post) five (5) days after being posted prepaid airmail and (if
     delivered personally or by facsimile transmission) at the time of actual
     delivery or (in the case of a facsimile transmission) on confirmation of
     transmission.

10.  GOVERNING LAW AND DISPUTE RESOLUTION

10.1 This Agreement is governed by and shall be construed in accordance with the
     laws of Kenya.

10.2 Any dispute or difference of any kind between the parties in connection
     with or arising out of this Agreement or the breach, termination or
     validity hereof (a "DISPUTE") shall be


                                       9



                                                              Security Agreement

     finally settled by arbitration under the Rules of Conciliation and
     Arbitration of the International Chamber of Commerce in accordance with the
     said Rules which Rules are deemed to be incorporated by reference into this
     Clause 10.2. It is hereby agreed that:

     (a)  the seat of the arbitration shall be London, England;

     (b)  there shall be a single arbitrator;

     (c)  the language of the arbitration shall be English;

     (d)  the award rendered shall apportion the costs of the arbitration;

     (e)  the award shall be in writing and shall set forth in reasonable detail
          the facts of the Dispute and the reasons for the tribunal's decision;

     (f)  the award in such arbitration shall be final and binding upon the
          Parties and judgment thereon may be entered into in any Court having
          jurisdiction for its enforcement; and the Parties renounce any right
          of appeal from the decision of the tribunal insofar as such
          renunciation can validly be made.

     If there is a conflict between this Agreement and the said Rules, this
     Agreement shall prevail.

10.3 Neither Party shall have any right to commence or maintain any legal
     proceeding concerning a Dispute relating to this agreement until the
     Dispute has been resolved in accordance with Clause 10.2, and then only to
     enforce or execute the award under such procedure.

10.4 The Parties shall each secure that all arbitrators and Experts shall agree
     to be bound by the provisions of Clause 6 of this Agreement as a condition
     of appointment.

10.5 The Parties shall continue to perform their obligations under this
     Agreement during any Expert or Arbitration proceeding.

10.6 Each Party hereby represents and warrants to the other that if any lawsuit
     or proceeding (including but not limited to all kinds of suits, court or
     arbitration proceedings, or enforcement of court decisions) related to this
     Agreement or the transactions contemplated in this Agreement is initiated
     against itself or is assets, it shall make no claim of immunity (sovereign
     or otherwise) from such lawsuit or proceeding on its behalf or for its
     assets.


                                       10





                                                              Security Agreement

11.  COUNTERPARTS

     This Agreement may be signed in any number of counterparts. Any single
     counterpart or a set of counterparts signed, in either case, by the Parties
     shall constitute a full and original Agreement for all purposes.

IN WITNESS whereof the parties hereto have executed and delivered this Agreement
as a Deed the day and year first before written.

SEALED with the COMMON SEAL of )
THE KENYA POWER AND            )
LIGHTING COMPANY LIMITED       )
In the presence of:            )

                       Director

                      Secretary

For and on behalf of           )

ORPOWER 4 INC. by Ernest Mabwa )   _____________________________________________

Authorised Representative


                                       11



                                                              Security Agreement

                                   SCHEDULE 1

                            FORM OF LETTER OF CREDIT

Draft LC TO: [ORPOWER 4, full address, to be advised to [Name of Advising Bank]]

1.   By order and for the account of our customer KPLC of Stima Plaza, Kolobot
     Road, P.O Box 30099-00100 Nairobi, we [Bank] this [__] day of [___] hereby
     establish and issue in your favour this irrevocable letter of credit (the
     "Letter of Credit") payable by means of drawings notify us pursuant hereto
     and at any particular time in the maximum amount of [words ____] [figures
     ____].

     The amount payable under this Letter of Credit shall be available in any
     number of drawings to and including the close of business in Nairobi on
     [__________] ("Expiry Date") against the following document to be presented
     at the offices of [__________], Nairobi:

     (a)  executed demand notice purportedly signed by your officer
          substantially in the form of the Appendix 1 attached hereto;

     (b)  a copy of an independent engineer certificate stating that Plant
          testing has been completed and the Plant is available for full
          commercial operation, [and

     (b)  the original of this Letter of Credit for endorsement.]

2.   If you present such demand notice and this Letter of Credit at such office
     on a Banking Day on or prior to the Expiry Date, we will honour the same by
     payment to you or in accordance with your instructions on or before the
     close of banking business on the fifth (5th) Banking Day after presentment
     thereof.

     The term "Banking Day" means a day (other than a Saturday or Sunday) on
     which banks are open for business in the Republic of Kenya.

3.   Subject to Clause 4, this Letter of Credit shall automatically terminate on
     the Expiry Date.

4.   If, from time to time, by the second Banking Day before the Expiry Date, we
     shall not have issued to you a replacement Letter of Credit by order and
     for the account of our customer, KPLC, in the form hereof (or in such other
     form as shall have substantially the same effect or as you and we may
     reasonably agree) unless otherwise instructed by you, you shall be deemed
     to have presented a demand notice on this Letter of Credit at our Nairobi
     office on such Banking Day for the amount available for drawing under this
     Letter of Credit and such deemed demand shall be honoured by us by payment
     of the amount available for drawing under the Letter of Credit into an
     account that we shall open as security and we will immediately renew the
     Letter of Credit for the amount


                                       12



                                                              Security Agreement

     deemed drawn down for a period of twelve (12) months from the then Expiry
     Date under the same terms and conditions (including the automatic renewal).
     Any such renewal shall be advised to OrPower 4 and KPLC at the address
     herein or such other address as may be notified to us by KPLC and OrPower 4
     from time to time.

5.   This Letter of Credit sets forth in full our undertaking, and such
     undertaking shall not in way be modified, amended, amplified or limited by
     reference to any document, instrument or agreement referred to herein,
     except only the certificates, the instructions to transfer and the drafts
     referred to herein; and any such reference shall not be deemed to
     incorporate herein by reference any document, instrument or agreement
     except for such certificate, such instructions to transfer and such drafts.

6.   This Letter of Credit is transferable in whole or in part.

7.   All Bank charges are for Applicant's account.

This Letter of Credit shall be governed by, and construed in accordance with the
Uniform Customs and Practice for Documentary Credits (1993 Revision),
International Chamber of Commerce Publication No. 500 provided that to the
extent that any of the provisions of this Letter of Credit are inconsistent with
or not covered by such Uniform Customs and Practice such provisions shall be
governed and construed in accordance with English law.

Communications with respect to this Letter of Credit shall be addressed to us at
[__________] attention [___] specifically referring to the number of this Letter
of Credit.


-------------------------------------
Yours faithfully,
Authorised Signatory


                                       13



                                                              Security Agreement

                                    APPENDIX
                              FORM OF DEMAND NOTICE

TO: [Bank]

Dear Sirs

We refer to Irrevocable Letter of Credit No. [__________] (the "Letter of
Credit") issued by you on the [__________] in our favour. In accordance with
Clause 1 thereof, we hereby state, that we are entitled to make this demand
under the Letter of Credit and hereby demand payment of [__________]
([__________]) without deduction or set off (except such as may be required by
law) to be made to our account number [__________] at [enter details of a bank
in [__________] on or before the fifth Banking Day (as defined in the Letter of
Credit) following your receipt of this demand.

Yours faithfully


---------------------------------------
authorised officer for and on behalf of

ORPOWER 4 INC

Copy: The Kenya Power and Lighting Company Limited


                                       14



                                                              Security Agreement

                                   SCHEDULE 2

                      FORM OF COMFORT LETTER - WAS PROVIDED

The Government of the Republic of Kenya ("GOK") is aware that OrPower 4 Inc.
("OrPower 4") is proposing to enter into a power purchase agreement with The
Kenya Power and Lighting Company Limited ("KPLC") pursuant to which OrPower 4
will: design, procure, construct, finance, test, commission, operate and
maintain a generation facility of 8 MW capacity at Olkaria III; appraise and
develop geothermal resources for the purposes of electricity generation at the
generation facility to be known as "Olkaria III"; design, procure, construct,
finance, test and commission a high voltage interconnector connecting OlkariaIII
with the 220 kV switchyard at the proposed Olkaria II generation facility;
design, procure, construct, finance, test, commission, operate and maintain a
generation facility of up to 100 MW capacity at Olkaria III; make available
generating capacity from Olkaria III to KPLC; and sell electricity generated
from Olkaria III to KPLC.

In accordance with GOK's policy on energy matters and private sector
participation in Kenya's electricity supply industry, GOK welcomes the
investment which OrPower 4 is proposing to make in the Republic of Kenya.

GOK recognises that in addition to making an equity investment in Olkaria III.
OrPower 4 will also require third party funding. GOK has been notified that in
order to secure such third party funding KPLC and OrPower 4 have agreed (as set
out in a security agreement) a form of security which KPLC will be obliged to
provide.

If KPLC will not provide the agreed security to OrPower 4 in accordance with its
contractual obligations, GOK will, following receipt of a written notification
from OrPower 4, use all means within its powers to cause KPLC to provide the
agreed security in the manner envisaged by its contractual obligations.

This letter is not intended to create any legal obligation on the part of GOK.

This letter is effective from the date on which KPLC and OrPower 4 execute the
security agreement referred to in paragraph 3.

This letter is issued pursuant to the laws of the Republic of Kenya.

Yours faithfully


                                       15



                                                              Security Agreement

SCHEDULE 3
FORM OF THE L/C BANK LETTER OF INSTRUCTION

To: [The L/C Bank]

We refer to the Olkaria III Project Security Agreement dated [__________] 2007
between The Kenya Power and Lighting Company Limited and OrPower 4 Inc. (the
"Security Agreement").

We enclose for your information a copy of the Olkaria III Project Security
Agreement together with a copy of the PPA referred to therein and receipt of
which you hereby acknowledge.

Words and expressions defined in the Olkaria III Project Security Agreement
shall have the same meanings in this letter.

A.   IRREVOCABLE RENEWAL INSTRUCTIONS

You are hereby irrevocably instructed that, if, by the second Business Day
before the then Expiry Date of a Letter of Credit, the Letter of Credit will not
have been renewed, you are to automatically draw all amounts then available for
drawing under the Letter of Credit, to deposit all such amounts in a depositary
account as security, and to immediately renew the Letter of Credit for periods
of additional 12 months each from the then Expiry Date of the Letter of Credit,
under the same terms and conditions.

You are further instructed to advise to Beneficiary by authenticated swift to
the advising bank

B.   GENERAL

1. You may,to the extent that you would have been entitled to rely on it if it
had been genuine, rely on any notice, instruction, communication, certificate,
legal opinion or other document which is not genuine but is reasonably believed
by you to be genuine; and retain for your own benefit and without liability to
account any fee or other sum receivable by you for your own account.

2. OrPower 4 will keep you informed of the amount of the Reserved Amount for the
purposes of this letter, both at the commencement of your appointment and from
time to time during the course of your appointment. Unless OrPower 4 informs you
in writing to the contrary, you may assume that the Reserved Amount is the
amount most recently notified to you as such.

3. The provisions of Clause 9 (Communications) of the Olkaria III Project
Security Agreement shall apply to this letter as they apply to the Olkaria III
Project Security Agreement. Your relevant details are as follows:

[L/C Bank]
Postal Address:
Fax Number:
Telephone Number:
Notices to be sent to:


                                       16





                                                              Security Agreement

4. This letter shall be governed by and construed in accordance with the laws of
the Republic of Kenya.

Please signify your agreement to the terms of this letter by signing and
returning to each of us one of the enclosed copies of this letter.

Yours faithfully                        Yours faithfully


-------------------------------------   ----------------------------------------
For and on behalf of                    For and on behalf of
The Kenya Power and                     OrPower 4 Inc
Lighting Company Limited


[On copy] We agree to the terms of the letter of which this is a copy.


For and on behalf of
[L/C Bank]


                                       17

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Forms S-3 (No. 333-131064) and S-8 (No. 333-129583) of Ormat Technologies, Inc. and subsidiaries of our report dated March 9, 2007 relating to the financial statements, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

San Francisco, California
March 9, 2007

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in this Annual Report (10-K) of Ormat Technologies, Inc. of our report dated March 27, 2006, with respect to the financial statements of Ormat Leyte Co. Ltd., included in the 2006 Annual Report to Shareholders of Ormat Technologies, Inc.

We consent to the incorporation by reference in the following Registration Statements:


(1)	Registration Statement (Form S-3 No. 333-131064)


(2)	Registration Statement (Form S-8 No. 333-129583)

of our report dated March 27, 2006, with respect to financial statements of Ormat Leyte Co. Ltd. incorporated herein by reference.

/s/ SyCip Gorres Velayo & Co.

Makati City, Philippines

March 7, 2007

Exhibit 31.1

Ormat Technologies, Inc.
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Yehudit Bronicki, certify that as of the date hereof:

1. I have reviewed this annual report on Form 10-K of Ormat Technologies, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under his/her supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent function):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 9, 2007


	By: /s/ YEHUDIT BRONICKI	Yehudit Bronicki Chief Executive Officer and President

Exhibit 31.2

Ormat Technologies, Inc.
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Joseph Tenne, certify that as of the date hereof:

1. I have reviewed this annual report on Form 10-K of Ormat Technologies, Inc.;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 9, 2007


	By: /s/ JOSEPH TENNE	Joseph Tenne Chief Financial Officer

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Yehudit Bronicki, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the annual report of Ormat Technologies, Inc. on Form 10-K for the year ended December 31, 2006 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such annual report on Form 10-K fairly presents in all material respects the financial condition, results of operations and cash flows of Ormat Technologies, Inc. as of and for the periods presented in such annual report on Form 10-K. This written statement is being furnished to the Securities and Exchange Commission as an exhibit accompanying such annual report and shall not be deemed filed pursuant to the Securities Exchange Act of 1934.

Date: March 9, 2007

By: /s/ YEHUDIT BRONICKI
Name: Yehudit Bronicki
Title: Chief Executive Officer and President

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Joseph Tenne, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the annual report of Ormat Technologies, Inc. on Form 10-K for the year ended December 31, 2006 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such annual report on Form 10-K fairly presents in all material respects the financial condition, results of operations and cash flows of Ormat Technologies, Inc. as of and for the periods presented in such annual report on Form 10-K. This written statement is being furnished to the Securities and Exchange Commission as an exhibit accompanying such annual report and shall not be deemed filed pursuant to the Securities Exchange Act of 1934.

Date: March 9, 2007

By: /s/ JOSEPH TENNE
Name: Joseph Tenne
Title: Chief Financial Officer